12266 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Parts 35 and 37 

[Docket Nos. RM05–17–000 and RM05–25– 

000; Order No. 890] 

Preventing Undue Discrimination and 

Preference in Transmission Service 

Issued February 16, 2007. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: The Federal Energy 

Regulatory Commission is amending the 

regulations and the pro forma open 

access transmission tariff adopted in 

Order Nos. 888 and 889 to ensure that 

transmission services are provided on a 

basis that is just, reasonable and not 

unduly discriminatory or preferential. 

The final rule is designed to: Strengthen 

the pro forma open-access transmission 

tariff, or OATT, to ensure that it 

achieves its original purpose of 

remedying undue discrimination; 

provide greater specificity to reduce 

opportunities for undue discrimination 

and facilitate the Commission’s 

enforcement; and increase transparency 

in the rules applicable to planning and 

use of the transmission system. 

EFFECTIVE DATE: This rule will become 

effective May 14, 2007. 

FOR FURTHER INFORMATION CONTACT: 

Daniel Hedberg (Technical Information), 

Office of Energy Markets and Reliability, 

Federal Energy Regulatory Commission, 

888 First Street, NE., Washington, DC 

20426, (202) 502–6243. 

W. Mason Emnett (Legal Information), 

Office of the General Counsel—Energy 

Markets, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502–6540. 

Kathleen Barro ́n (Legal Information), 

Office of the General Counsel—Energy 

Markets, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502–6461. 

SUPPLEMENTARY INFORMATION: 

Table of Contents Paragraph 

Nos. 

I. Introduction ........................................................................................................................................................................................... 1 

II. Background ........................................................................................................................................................................................... 9 

A. Historical Antecedent .................................................................................................................................................................. 9 

B. Order No. 888 and Subsequent Reforms ..................................................................................................................................... 14 

C. EPAct 2005 and Recent Developments ....................................................................................................................................... 22 

III. Need for Reform of Order No. 888 .................................................................................................................................................... 26 

A. Opportunities for Undue Discrimination Continue to Exist ..................................................................................................... 26 

B. Lack of Transparency Undermines Confidence in Open Access and Impedes Enforcement of Open Access Requirements 44 

C. Congestion and Inadequate Infrastructure Development Impede Customers’ Use of the Grid ............................................... 52 

D. A Consistent Method of Measuring ATC Is Needed .................................................................................................................. 62 

E. Discriminatory Pricing of Imbalances .......................................................................................................................................... 70 

F. Redispatch/Conditional Firm ....................................................................................................................................................... 73 

G. EPAct 2005 Emphasized Certain Policies and Priorities for the Commission ......................................................................... 79 

IV. Summary, Scope and Applicability of the Final Rule ..................................................................................................................... 82 

A. Summary of Reforms .................................................................................................................................................................... 83 

B. Core Elements of Order No. 888 That Are Retained .................................................................................................................. 91 

1. Federal/State Jurisdiction ...................................................................................................................................................... 92 

2. Native Load Protection .......................................................................................................................................................... 95 

3. The Types of Transmission Services Offered ...................................................................................................................... 110 

4. Functional Unbundling ......................................................................................................................................................... 117 

C. Applicability of the Final Rule .................................................................................................................................................... 124 

1. Non-ISO/RTO Public Utility Transmission Providers ......................................................................................................... 124 

2. ISO and RTO Public Utility Transmission Providers and Transmission Owner Members of ISOs and RTOs ............... 143 

3. Non-Public Utility Transmission Providers/Reciprocity ..................................................................................................... 162 

V. Reforms of the OATT .......................................................................................................................................................................... 193 

A. Consistency and Transparency of ATC Calculations ................................................................................................................. 193 

B. Coordinated, Open and Transparent Planning ........................................................................................................................... 418 

C. Transmission Pricing .................................................................................................................................................................... 603 

1. General .................................................................................................................................................................................... 603 

2. Energy and Generation Imbalances ....................................................................................................................................... 627 

3. Credits for Network Customers ............................................................................................................................................. 729 

4. Capacity Reassignment .......................................................................................................................................................... 778 

5. ‘‘Operational’’ Penalties ......................................................................................................................................................... 826 

a. Unreserved Use Penalties ............................................................................................................................................... 826 

b. Distribution of Operational Penalties ............................................................................................................................ 850 

c. Applicability of Operational Penalties Proposal to RTOs and Other Independent or Non-Profit Entities ............... 866 

6. ‘‘Higher of’’ Pricing Policy .................................................................................................................................................... 870 

7. Other Ancillary Services ....................................................................................................................................................... 886 

D. Non-Rate Terms and Conditions ................................................................................................................................................. 901 

1. Modifications to Long-Term Firm Point-to-Point Service ................................................................................................... 901 

a. Planning Redispatch and Conditional Firm Options ................................................................................................... 901 

b. Proposals for Transparent Redispatch ........................................................................................................................... 1095 

c. Other Requested Service Modifications ........................................................................................................................ 1165 

2. Hourly Firm Service .............................................................................................................................................................. 1177 

3. Rollover Rights ....................................................................................................................................................................... 1214 

4. Modification of Receipt or Delivery Points .......................................................................................................................... 1268 

5. Acquisition of Transmission Service .................................................................................................................................... 1296 

a. Processing of Service Requests ...................................................................................................................................... 1296 

b. Reservation Priority ........................................................................................................................................................ 1394 

6. Designation of Network Resources ....................................................................................................................................... 1432 

a. Qualification as a Network Resource ............................................................................................................................. 1432 


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1Promoting Wholesale Competition Through 

Open Access Non-discriminatory Transmission 

Services by Public Utilities; Recovery of Stranded 

Costs by Public Utilities and Transmitting Utilities, 

Order No. 888, 61 FR 21540 (May 10, 1996), FERC 

Stats. & Regs. § 31,036 (1996), order on reh’g, Order 

No. 888–A, 62 FR 12274 (Mar. 14, 1997), FERC 

Stats. & Regs. § 31,048 (1997), order on reh’g, Order 

No. 888–B, 81 FERC § 61,248 (1997), order on reh’g, 

Order No. 888–C, 82 FERC § 61,046 (1998), aff’d in 

relevant part sub nom. Transmission Access Policy 

Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000) 

(TAPS v. FERC), aff’d sub nom. New York v. FERC, 

535 U.S. 1 (2002). 

2Preventing Undue Discrimination and 

Preference in Transmission Service, Notice of 

Proposed Rulemaking, 71 FR 32,636 (Jun. 6, 2006), 

FERC Stats. & Regs. § 32,603 (2006). 

3The Commission used the term ‘‘Available 

Transmission Capability’’ in Order No. 888 to 

describe the amount of additional capability 

available in the transmission network to 

accommodate additional requests for transmission 

services. To be consistent with the term generally 

accepted throughout the industry, the Commission 

revises the pro forma OATT to adopt the term 

‘‘Available Transfer Capability.’’

4Congress placed special emphasis on the 

development of transmission infrastructure, 

including the consideration of advanced 

transmission technologies, in the Energy Policy Act 

of 2005 (EPAct 2005). See Pub. L. 109–58, 119 Stat. 

594 (to be codified in scattered titles of the U.S.C.). 

The Commission has taken steps to implement that 

goal in numerous contexts, including recent 

rulemaking proceedings that address the promotion 

of transmission investment through pricing reform 

and the siting of certain transmission facilities. See 

Promoting Transmission Investment through 

Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 

31, 2006), FERC Stats. & Regs. § 31,222 (2006), order 

on reh’g, Order No. 679–A, 72 FR 1152 (Jan. 10, 

2007), FERC Stats. & Regs. § 31,236 (2007), reh’g 

pending; Regulations for Filing Applications for 

Permits to Site Interstate Electric Transmission 

Facilities, Order No. 689, 71 FR 69440 (Dec. 1, 

2006), FERC Stats. & Regs. § 31,234 (2006), reh’g 

pending. As discussed herein, several actions taken 

in this Final Rule also relate to the need for 

investments in transmission infrastructure and are 

consistent with the Commission’s responsibilities 

under EPAct 2005. 

Table of Contents Paragraph 

Nos. 

b. Documentation for Network Resources ......................................................................................................................... 1507 

c. Undesignation of Network Resources ............................................................................................................................ 1534 

7. Clarifications Related to Network Service ............................................................................................................................ 1592 

a. Secondary Network Service ........................................................................................................................................... 1592 

b. Behind the Meter Generation ......................................................................................................................................... 1614 

8. Transmission Curtailments .................................................................................................................................................... 1620 

9. Standardization of Rules and Practices ................................................................................................................................ 1633 

a. Business Practices ........................................................................................................................................................... 1633 

b. Liability and Indemnification ........................................................................................................................................ 1662 

10. OATT Definitions ................................................................................................................................................................ 1678 

E. Enforcement .................................................................................................................................................................................. 1714 

1. General Policy ........................................................................................................................................................................ 1715 

2. Civil Penalties ........................................................................................................................................................................ 1724 

VI. Information Collection Statement ...................................................................................................................................................... 1752 

VII. Environmental Analysis .................................................................................................................................................................... 1758 

VIII. Regulatory Flexibility Act Analysis ................................................................................................................................................ 1759 

IX. Document Availability ....................................................................................................................................................................... 1760 

X. Effective Date and Congressional Notification ................................................................................................................................... 1763 

Appendix A: Summary of Compliance Filing Requirements 

Appendix B: Commenting Party Acronyms 

Appendix C: Pro Forma Open Access Transmission Tariff 

Before Commissioners: Joseph T. 

Kelliher, Chairman; Suedeen G. 

Kelly, Marc Spitzer, Philip D. 

Moeller, and Jon Wellinghoff. 

I. Introduction 

1. This Final Rule addresses and 

remedies opportunities for undue 

discrimination under the pro forma 

Open Access Transmission Tariff 

(OATT) adopted in 1996 by Order No. 

888.1 This landmark rulemaking 

fostered greater competition in 

wholesale power markets by reducing 

barriers to entry in the provision of 

transmission service. In the ten years 

since Order No. 888, however, the 

Commission has found that the OATT 

contains flaws that undermine realizing 

its core objective of remedying undue 

discrimination. In the Notice of 

Proposed Rulemaking (NOPR) issued on 

May 19, 2006, the Commission 

proposed to remedy those flaws.2 After 

receiving approximately 6,500 pages of 

comments from close to 300 parties, we 

now take final action. We highlight 

below the most critical reforms being 

adopted today. 

2. First, the Final Rule will increase 

nondiscriminatory access to the grid by 

eliminating the wide discretion that 

transmission providers currently have 

in calculating available transfer 

capability (ATC).3 The calculation of 

ATC is one of the most critical functions 

under the OATT because it determines 

whether transmission customers can 

access alternative power supplies. 

Despite this, the existing OATT does not 

prescribe how ATC should be calculated 

because the Commission sought to rely 

on voluntary efforts by the industry to 

develop consistent methods of ATC 

calculation. This voluntary industry 

effort has not proven successful. The 

Commission therefore acts today to 

require public utilities, working through 

the North American Electric Reliability 

Corporation (NERC), to develop 

consistent methodologies for ATC 

calculation and to publish those 

methodologies to increase transparency. 

This important reform will eliminate the 

wide discretion that exists today in 

calculating ATC and ensure that 

customers are treated fairly in seeking 

alternative power supplies. 

3. Second, the Final Rule will 

increase the ability of customers to 

access new generating resources and 

promote efficient utilization of 

transmission by requiring an open, 

transparent, and coordinated 

transmission planning process. 

Transmission planning is a critical 

function under the pro forma OATT 

because it is the means by which 

customers consider and access new 

sources of energy and have an 

opportunity to explore the feasibility of 

non-transmission alternatives. Despite 

this, the existing pro forma OATT 

provides limited guidance regarding 

how transmission customers are treated 

in the planning process and provides 

them very little information on how 

transmission plans are developed. These 

deficiencies are serious, given the 

substantial need for new infrastructure 

in this Nation.4 We act today to remedy 

these deficiencies by requiring 

transmission providers to open their 

transmission planning process to 

customers, coordinate with customers 

regarding future system plans, and share 

necessary planning information with 

customers. 

4. Third, the Final Rule will also 

increase the efficient utilization of 


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5Preventing Undue Discrimination and 

Preference in Transmission Services, Notice of 

Inquiry, 112 FERC ¶ 61,299 (2005) (NOI); 

Information Requirements for Available Transfer 

Capability, Notice of Inquiry, 111 FERC ¶ 61,274 

(2005) (ATC NOI). 

6Pub. L. 95–617, 92 Stat. 3117 (1978) (codified 

in U.S.C. titles 15, 16, 26, 30, 42, and 43). 7Section 211 of the FPA, 16 U.S.C. 824j. In earlier 

years, a few customers were able to obtain access 

as a result of litigation, beginning with the U.S. 

Supreme Court’s decision in Otter Tail Power 

Company v. United States, 410 U.S. 366 (1973). 

Additionally, some customers gained access by 

virtue of Nuclear Regulatory Commission license 

conditions and voluntary preference power 

transmission arrangements associated with Federal 

power marketing agencies. See, e.g., Consumers 

Power Co., 6 NRC 887, 1036–44 (1977); Toledo 

Edison Co., 10 NRC 265, 327–34 (1979); Florida 

Municipal Power Agency v. Florida Power and Light 

Co., 839 F. Supp. 1563 (M.D. Fla. 1993). 

transmission by eliminating artificial 

barriers to use of the grid. The existing 

pro forma OATT allows a transmission 

provider to deny a request for long-term 

point-to-point service if the request 

cannot be satisfied in only one hour of 

the requested term. This practice 

discourages the efficient use of the 

existing grid and precludes access to 

alternative power supplies. We reform 

this practice by requiring that a 

conditional firm option be offered to 

customers seeking long-term point-topoint service, i.e., conditional firm 

service. We also modify the redispatch 

obligations of transmission providers to 

increase the efficient utilization of the 

grid, while also ensuring that reliability 

to native load customers is maintained. 

5. Fourth, by adopting these and other 

reforms, the Final Rule facilitates the 

use of clean energy resources such as 

wind power. Conditional firm service is 

particularly important to wind resources 

that can provide significant economic 

and environmental value even if 

curtailed under limited circumstances. 

Open and coordinated transmission 

planning will enhance the ability of 

customers to access clean energy 

resources as part of their future resource 

portfolio. The Final Rule also benefits 

clean energy resources by reforming 

energy and generator imbalance charges. 

These reforms are particularly important 

to intermittent resources such as wind 

power because these resources have 

limited ability to control their output 

and, hence, must be assured that 

imbalance charges are no more than 

required to provide appropriate 

incentives for prudent behavior. 

6. Fifth, the Final Rule will strengthen 

compliance and enforcement efforts. We 

are increasing the transparency of pro 

forma OATT administration, thereby 

increasing the ability of customers and 

our Office of Enforcement to detect 

undue discrimination. We are adopting 

operational penalties for clear violations 

of an OATT, thereby enhancing 

compliance while also reducing the 

burdens on our Office of Enforcement. 

We are also increasing the clarity of 

many other OATT requirements, 

thereby facilitating compliance by 

transmission providers with our 

regulations. This Final Rule thus reflects 

the close integration of our Office of 

Enforcement into policy development at 

the Commission. Several of the reforms 

we adopt today are informed by our 

experience with OATT administration 

through oversight, audits, and 

investigations performed by the Office 

of Enforcement. 

7. Finally, we modify and improve 

several provisions of the pro forma 

OATT using our experience over the 

past ten years and clarify others that 

have proven ambiguous. For example, 

we reform our rollover rights policy to 

ensure that the rights and obligations of 

rollover customers are consistent with 

the resulting obligations of transmission 

providers to plan and upgrade the 

system to accommodate rollovers. We 

remove the price cap on reassigned 

capacity because it is not necessary to 

remedy market power and doing so will 

otherwise increase the efficient use of 

existing capacity. We increase the 

efficient use of existing capacity by 

providing a priority to certain ‘‘preconfirmed’’ requests for service. We 

increase certainty by providing greater 

clarity regarding the wholesale contracts 

that qualify as network resources. We 

also adopt numerous clarifications that 

should assist transmission providers 

and customers in implementing and 

using the pro forma OATT 

8. Our actions in this proceeding have 

been informed to a great extent by the 

comments received in response to our 

notices of inquiry in the abovecaptioned dockets and the subsequent 

NOPR.5 We appreciate the time and 

thoughtfulness of all sectors of the 

industry in preparing comments. We 

have found them very informative and 

useful in reaching our decisions in this 

Final Rule. 

II. Background 

A. Historical Antecedent 

9. In the NOPR, the Commission 

explained the historical background that 

led up to the issuance of Order No. 888, 

and the initiation of this rulemaking 

proceeding. We repeat that history here 

to place in context the actions we take 

today. 

10. In the first few decades after 

enactment of the Federal Power Act 

(FPA) in 1935, the industry was 

characterized mostly by self-sufficient, 

vertically integrated electric utilities, in 

which generation, transmission, and 

distribution facilities were owned by a 

single entity and sold as part of a 

bundled service to wholesale and retail 

customers. Most electric utilities built 

their own power plants and 

transmission systems, entered into 

interconnection and coordination 

arrangements with neighboring utilities, 

and entered into long-term contracts to 

make wholesale requirements sales 

(bundled sales of generation and 

transmission) to municipal, cooperative, 

and investor-owned utilities connected 

to each utility’s transmission system. 

Each system covered a limited service 

area, which was defined by the retail 

franchise decisions of State regulatory 

agencies. This structure of separate 

systems arose naturally primarily due to 

cost and the technological limitations 

on the distance over which electricity 

could be transmitted. 

11. A number of statutory, economic, 

and technological developments in the 

1970s led to an increase in coordinated 

operations and competition. Among 

those was the passage of the Public 

Utility Regulatory Policies Act of 1978 

(PURPA),6 which was designed to 

lessen dependence on foreign fossil 

fuels by encouraging the development of 

alternative generation sources and 

imposing a mandatory purchase 

obligation on utilities for generation 

from such sources. PURPA also enabled 

the Commission to order wheeling of 

electricity under limited 

circumstances.7 The rapid expansion 

and performance of the independent 

power industry following the enactment 

of PURPA demonstrated that traditional, 

vertically integrated public utilities 

need not be the only sources of reliable 

power. During this period, the profile of 

generation investment began to change, 

and a market for non-traditional power 

supply beyond the purchases required 

by PURPA began to emerge. The 

economic and technological changes in 

the transmission and generation sectors 

helped encourage many new entrants in 

the generating markets that could sell 

electric energy profitably with smaller 

scale technology at a lower price than 

many utilities selling from their existing 

generation facilities at rates reflecting 

cost. However, it became increasingly 

clear that the potential consumer 

benefits that could be derived from 

these technological advances could be 

realized only if more efficient generating 

plants could obtain access to the 

regional transmission grids. Because 

many traditional vertically integrated 

utilities still did not provide open 

access to third parties and favored their 

own generation if and when they 


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8See, e.g., Dartmouth Power Associates Limited 

Partnership, 53 FERC ¶ 61,117 (1990); 

Commonwealth Atlantic Limited Partnership, 51 

FERC ¶ 61,368 (1990); Doswell Limited Partnership, 

50 FERC ¶ 61,251 (1990); Citizens Power & Light 

Co., 48 FERC ¶ 61,210 (1989); Ocean State Power, 

44 FERC ¶ 61,261 (1988); and Orange and Rockland 

Utilities, Inc., 42 FERC ¶ 61,012 (1988). 

9See Order No. 888 at 31,644 n.52. 

10Pub. L. 102–486, 106 Stat. 2776 (1992) 

(codified at, among other places, 15 U.S.C. 79z–5a 

and 16 U.S.C. 796 (22–25), 824j–l). 

11 15 U.S.C. 79a, repealed by EPAct 2005 sec. 

1263; see Repeal of the Public Utility Holding 

Company Act of 1935 and Enactment of the Public 

Utility Holding Company Act of 2005, Order No. 

667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. & 

Regs. ¶ 31,197 (2005), order on reh’g, Order No. 

667–A, 71 FR 28446 (May 16, 2006), FERC Stats. 

& Regs. ¶ 31,213 (2006), order on reh’g, Order No. 

667–B, 71 FERC 42750 (Jul. 28, 2006), FERC Stats. 

& Regs. ¶ 31,224 (2006), reh’g pending. 

12 16 U.S.C. 824j (authorizing the Commission to 

require transmission utilities to provide service in 

certain circumstances); 16 U.S.C. 824k (establishing 

rates for service provided pursuant to an order 

under section 211). 

13This is known as ‘‘functional unbundling’’

because the transmission element of a wholesale 

sale is separated or unbundled from the generation 

element of that sale, although the public utility may 

provide both functions. See infra section IV.B.4 of 

this Final Rule. 

14See Order No. 888 at 31,769–70 (noting that the 

pro forma OATT expressly identified certain nonrate terms and conditions, such as the time 

deadlines for determining available transfer 

capability in section 18.4 or scheduling changes in 

sections 13.8 and 14.6, that may be modified to 

account for regional practices if such practices are 

reasonable, generally accepted in the region, and 

consistently adhered to by the transmission 

provider). 

15Order No. 888 at 31,655. 

16 Id. at 31,730–32. 

provided transmission access to third 

parties, access to cheaper, more efficient 

generation sources remained limited. 

12. The Commission encouraged the 

development of independent power 

producers (IPPs), as well as emerging 

power marketers, by authorizing marketbased rates for their power sales on a 

case-by-case basis, and by encouraging 

more widely available transmission 

access on a case-by-case basis. Marketbased rates helped to develop 

competitive bulk power markets by 

allowing generating utilities to move 

more quickly and flexibly to take 

advantage of short-term or even longterm market opportunities than those 

utilities operating under traditional 

cost-of-service tariffs. In approving these 

market-based rates, the Commission 

required that the seller and its affiliates 

lack market power or mitigate any 

market power that they may have had.8

The major concern of the Commission 

was whether the seller or its affiliates 

could limit competition and thereby 

drive up prices. A key inquiry became 

whether the seller or its affiliates owned 

or controlled transmission facilities in 

the relevant service area and therefore, 

by denying access or imposing 

discriminatory terms or conditions on 

transmission service, could foreclose 

other generators from competing. 

Beginning in the late 1980s, in order to 

mitigate their market power to meet the 

Commission’s conditions, public 

utilities seeking Commission 

authorization for blanket approval of 

market-based rates for generation 

services under section 205 of the FPA 

filed ‘‘open access’’ transmission tariffs 

of general applicability.9 The 

Commission also approved proposed 

mergers under section 203 of the FPA 

on the condition that the merging 

companies remedy anticompetitive 

effects potentially caused by the merger 

by filing ‘‘open access’’ tariffs. The early 

tariffs submitted in market-based rate 

proceedings under section 205 and 

merger proceedings under section 203 

did not, however, provide access to the 

transmission system that was 

comparable to the service the 

transmission providers used for their 

own purposes. Rather, they typically 

made available only point-to-point 

transmission service, i.e., service from a 

single point of receipt to a single point 

of delivery. As these early tariffs were 

offered only by transmission providers 

that volunteered to provide service to 

third parties, they resulted in a 

patchwork of open access that was not 

sufficient to facilitate wholesale 

generation markets. 

13. In response to the competitive 

developments following PURPA, and 

the fact that limited transmission access 

and significant regulatory barriers 

continued to constrain the development 

of generation by independent power 

producers, Congress enacted Title VII of 

the Energy Policy Act of 1992 (EPAct 

1992).10 EPAct 1992 reduced regulatory 

barriers to entry by creating a class of 

‘‘Exempt Wholesale Generators’’ that 

were exempt from the requirements of 

the Public Utility Holding Company Act 

of 1935.11 EPAct 1992 also expanded 

the Commission’s authority to approve 

applications for transmission services 

under sections 211 and 212 of the 

FPA.12 Though the Commission 

aggressively implemented expanded 

section 211, it ultimately concluded that 

the procedural limitations in section 

211 thwarted the Commission’s ability 

to effectively eliminate undue 

discrimination in the provision of 

transmission service. 

B. Order No. 888 and Subsequent 

Reforms 

14. In April 1996, as part of its 

statutory obligation under sections 205 

and 206 of the FPA to remedy undue 

discrimination, the Commission 

adopted Order No. 888 prohibiting 

public utilities from using their 

monopoly power over transmission to 

unduly discriminate against others. In 

that order, the Commission required all 

public utilities that own, control or 

operate facilities used for transmitting 

electric energy in interstate commerce to 

file open access non-discriminatory 

transmission tariffs that contained 

minimum terms and conditions of nondiscriminatory service. It also obligated 

such public utilities to ‘‘functionally 

unbundle’’ their generation and 

transmission services. This meant 

public utilities had to take transmission 

service (including ancillary services) for 

their own new wholesale sales and 

purchases of electric energy under the 

open access tariffs, and to separately 

state their rates for wholesale 

generation, transmission and ancillary 

services.13 Each public utility was 

required to file the pro forma OATT 

included in Order No. 888 without any 

deviation (except a limited number of 

terms and conditions that reflect 

regional practices).14 After the 

effectiveness of their OATTs, public 

utilities were allowed to file, pursuant 

to section 205 of the FPA, deviations 

that were consistent with or superior to 

the pro forma OATT’s terms and 

conditions. Because certain owners, 

controllers or operators of interstate 

transmission facilities were not subject 

to the Commission’s jurisdiction under 

sections 205 and 206 and thus were not 

subject to Order No. 888, the 

Commission adopted a reciprocity 

provision in the pro forma OATT that 

conditions the use by a non-public 

utility of a public utility’s open access 

services on an agreement to offer nondiscriminatory transmission services in 

return. 

15. In addition to imposing the 

functional unbundling requirement, the 

Commission also encouraged broader 

reforms through the formation of 

independent system operators (ISOs). 

The Commission stated that ISOs can 

provide significant benefits such as 

enhancing regional efficiencies and 

further remedying undue 

discrimination.15 While the 

Commission declined to mandate ISOs, 

it set forth eleven principles for 

assessing ISO proposals submitted to 

the Commission.16

16. Order No. 888 also clarified the 

Commission’s interpretation of the 

Federal and State jurisdictional 

boundaries over transmission and local 

distribution. While Order No. 888 

reaffirmed that the Commission has 

exclusive jurisdiction over the rates, 


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17New York v. FERC, 535 U.S. 1 (2002). 

18Open Access Same-Time Information System 

(Formerly Real-Time Information Networks) and 

Standards of Conduct, Order No. 889, 61 FR 21737 

(May 10, 1996), FERC Stats. & Regs. ¶ 31,035 (1996), 

order on reh’g, Order No. 889–A, FERC Stats. & 

Regs. ¶ 31,049 (1997), order on reh’g, Order No. 

889–B, 81 FERC ¶ 61,253 (1997). 

19Order No. 889 at 31,605. 

20 Id. at 31,607. 

21 Id. 

22 Id. 

23See Energy Information Administration, Retail 

Unbundling—U.S. Summary (2005), http://www.

eia.doe.gov/oil_gas/natural_gas/restructure/state/ 

us.html. 

24Regional Transmission Organizations, Order 

No. 2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & 

Regs. ¶ 31,089 (1999), order on reh’g, Order No. 

2000–A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. 

& Regs. ¶ 31,092 (2000), aff’d sub nom. Public 

Utility District No. 1 of Snohomish County, 

Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001). 

25Order No. 2000 at 31,015. 

26 Id. at 30,993. 

27A list of commenter acronyms can be found in 

Appendix B. 

28EPAct 2005 sec. 1241 (to be codified at section 

219 of the FPA, 16 U.S.C. 824s). 

terms, and conditions of unbundled 

retail transmission in interstate 

commerce by public utilities, it 

nevertheless recognized the legitimate 

concerns of State regulatory authorities 

regarding the transmission component 

of bundled retail sales. The Commission 

therefore declined to extend its 

unbundling requirement to the 

transmission component of bundled 

retail sales. On appeal, the U.S. 

Supreme Court affirmed this element of 

Order No. 888, finding that the 

Commission made a statutorily 

permissible choice.17

17. The same day it issued Order No. 

888, the Commission issued a 

companion order, Order No. 889,18

addressing the separation of vertically 

integrated utilities’ transmission and 

merchant functions, the information 

transmission providers were required to 

make public, and the electronic means 

they were required to use to do so. 

Order No. 889 imposed Standards of 

Conduct governing the separation of, 

and communications between, the 

utility’s transmission and wholesale 

power functions, to prevent the utility 

from giving its merchant arm 

preferential access to transmission 

information. All public utilities that 

owned, controlled or operated facilities 

used in the transmission of electric 

energy in interstate commerce were 

required to create or participate in an 

Open Access Same-Time Information 

System (OASIS) that was to provide 

existing and potential transmission 

customers the same access to 

transmission information. 

18. Among the information public 

utilities were required to post on their 

OASIS was the transmission provider’s 

calculation of ATC. Though the 

Commission acknowledged that beforethe-fact measurement of the availability 

of transmission service is ‘‘difficult,’’ it 

concluded that it was important to give 

potential transmission customers ‘‘an 

easy-to-understand indicator of service 

availability.’’ 19 Because formal methods 

did not then exist to calculate ATC and 

total transfer capability (TTC), the 

Commission encouraged industry efforts 

to develop consistent methods for 

calculating ATC and TTC.20 Order No. 

889 ultimately required transmission 

providers to base their calculations on 

‘‘current industry practices, standards 

and criteria’’ and to describe their 

methodology in their tariffs.21 The 

Commission noted that the requirement 

that transmission providers purchase 

only ATC that is posted as available 

‘‘should create an adequate incentive for 

them to calculate ATC and TTC as 

accurately and as uniformly as 

possible.’’ 22

19. The electric industry continued to 

undergo economic and regulatory 

changes in the years following the 

issuance of Order No. 888. Retail access 

was adopted by approximately 25 states 

in the late 1990s.23 This State 

restructuring activity spurred significant 

changes at the wholesale level as well 

by encouraging or requiring the 

divestiture of generation plants by 

traditional electric utilities and the 

development of ISOs that could manage 

short-term energy markets necessary to 

support retail access. At the same time, 

there was a significant increase in the 

number of mergers between traditional 

electric utilities and between electric 

utilities and gas pipeline companies, 

and large increases in the number of 

power marketers and independent 

generation facility developers entering 

the marketplace. Trade in bulk power 

markets increased significantly and the 

Nation’s transmission grid was used 

more heavily and in new ways as 

customers took advantage of the pro 

forma OATT and purchased power from 

competitive sellers. 

20. In the wake of these changes, in 

December 1999, the Commission 

adopted Order No. 2000.24 That 

rulemaking recognized that Order No. 

888 set the foundation upon which 

competitive electric markets could 

develop, but did not eliminate the 

potential to engage in undue 

discrimination and preference in the 

provision of transmission service.25 The 

rulemaking also recognized that Order 

No. 888 did not address the regional 

nature of the grid, including the 

treatment of parallel flows, pancaked 

rates, and congestion management. 

Thus, the Commission encouraged the 

creation of RTOs to address important 

operational and reliability issues and 

eliminate any residual discrimination in 

transmission services that can occur 

when the operation of the transmission 

system remains in the control of a 

vertically integrated utility. The 

Commission found that RTOs would 

increase the efficiency of wholesale 

markets by eliminating pancaked rates, 

internalizing parallel flow, managing 

congestion efficiently, and operating 

markets for energy, capacity and 

ancillary services. The Commission 

established an open, collaborative 

process that relied on voluntary regional 

participation to design RTOs tailored to 

the specific needs of each region. The 

Commission noted, however, that ‘‘[i]f 

the industry fails to form RTOs under 

this approach, the Commission will 

reconsider what further regulatory steps 

are in the public interest.’’26

21. Following Order No. 2000, RTOs 

were approved in several regions of the 

country including the Northeast (PJM; 

ISO New England),27 the Midwest 

(MISO) and the South (SPP). In most 

cases, RTOs have assumed 

responsibility for calculating ATC 

across the footprint of the RTO, as well 

as the planning and expansion of the 

transmission grid, at least for facilities 

necessary for maintaining system 

reliability. However, large areas of the 

Nation have not developed RTOs using 

the voluntary structure adopted by the 

Commission in Order No. 2000. 

Moreover, transmission customers have 

complained that even in RTO markets 

there are instances when comparable 

transmission service is not provided, 

particularly in the area of transmission 

planning. 

C. EPAct 2005 and Recent 

Developments 

22. Enacted on August 8, 2005, EPAct 

added a number of new authorities and 

priorities for the Commission and 

emphasized certain of its existing 

obligations. Among other things, EPAct 

2005 recognized the importance of 

adequate transmission infrastructure 

development and its role in facilitating 

the development of competitive 

wholesale markets. The Congressional 

directives in EPAct 2005 are intended to 

reverse the decline in transmission 

infrastructure investment. For example, 

Congress required the Commission to 

adopt a rule establishing incentive 

ratemaking for transmission 

infrastructure to help promote reliability 

and reduce congestion.28 Congress also 


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29EPAct 2005 sec. 1223 (to be codified at 42 

U.S.C. 16422). Indeed, Congress provided specific 

guidance as to the types of advanced technologies 

that should be encouraged in infrastructure 

improvements to include, among others, optimized 

transmission line configurations (including 

multiple phased transmission lines), controllable 

load, distributed generation (including PV, fuel 

cells, and microturbines), and enhanced power 

device monitoring. Id. 30EPAct 2005 sec. 1233(a) (to be codified at 

section 217(b)(4) of the FPA, 16 U.S.C. 824q). 31EPAct 2005 sec. 1221(a) (to be codified at 

section 216 of the FPA, 16 U.S.C. 824p). 32EPAct 2005 sec. 1231 (to be codified at section 

211A of the FPA, 16 U.S.C. 824j–1) 33EPAct 2005 sec. 1234 (to be codified at 42 

U.S.C. 16432); EPAct 2005 sec. 1298 (to be codified 

at section 223 of the FPA, 16 U.S.C. 824w). EPAct 

2005 sec. 1234(b) defined economic dispatch as 

‘‘the operation of generation facilities to produce 

energy at the lowest cost to reliably serve 

consumers, recognizing any operational limits of 

generation and transmission facilities.’’ 34EPAct 2005 sec. 1281 (to be codified at section 

220 of the FPA, 16 U.S.C. 824t). 

35EPAct 2005 sec. 1284(d) (to be codified at 

section 316 of the FPA, 16 U.S.C. 825o); EPAct 2005 

sec. 1284(e) (to be codified at section 316A of the 

FPA, 16 U.S.C. 825o–1). 36See supra note 5. 37 Id. 38Preventing Undue Discrimination and 

Preference in Transmission Service, 117 FERC 

¶ 61,185 (2006). 

39Order No. 2000 at 31,105. 

40See Standardization of Generator 

Interconnection Agreements and Procedures, Order 

No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats. 

& Regs. ¶ 31,146 at P 11–12 (2003), order on reh’g, 

Order No. 2003–A, 69 FR 15932 (Mar. 26, 2004), 

FERC Stats. & Regs. ¶ 31,160 (2004), order on reh’g, 

Order No. 2003–B, 70 FR 265 (Jan. 4, 2005), FERC 

Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order 

No. 2003–C, 70 FR 37,661 (Jun. 30, 2005), FERC 

Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom. 

National Association of Regulatory Utility 

Commissioners v. FERC, No. 04–1148, 2007 U.S. 

App. LEXIS 626 (D.C. Cir. Jan. 12, 2007). 

41Order No. 2003 at P 11–12. 

42E.g., APPA, EPSA, East Texas Cooperatives, 

Fayetteville, NRG, Occidental, TAPS, TDU Systems, 

Williams, Entegra Reply, and NRECA Reply. 

directed the Commission to encourage 

the deployment of advanced 

technologies.29 Congress further 

directed the Commission to ‘‘exercise its 

authority’’ under EPAct 2005 ‘‘in a 

manner that facilitates the planning and 

expansion of transmission facilities to 

meet the reasonable needs of loadserving entities.’’30 Congress also gave 

the Commission certain ‘‘backstop’’

transmission siting authority, and 

authorized the creation of interstate 

compacts establishing transmission 

siting agencies.31 EPAct 2005 also 

authorized the Commission to require 

unregulated transmitting utilities 

(except for certain small entities) to 

provide access to their transmission 

facilities on a comparable basis.32

Congress further ordered the 

Department of Energy (DOE) to study 

the benefits of economic dispatch and 

required the Commission to convene 

regional joint boards to develop a report 

to Congress containing 

recommendations for the use of security 

constrained economic dispatch within 

each region.33 Congress also directed the 

Commission to facilitate price 

transparency in markets for the sale and 

transmission of electric energy in 

interstate commerce, having due regard 

for the public interest, the integrity of 

those markets, fair competition, and the 

protection of consumers, and it 

authorized the Commission to prescribe 

rules to provide for the dissemination of 

information about the availability and 

price of wholesale electric energy and 

transmission service.34 Finally, 

Congress emphasized compliance with 

the Commission’s regulations, adopting 

and increasing the civil and criminal 

penalties for violations of Commissionadministered statutes and regulations.35

23. Recognizing the need for reform of 

Order No. 888 in light of the 

Commission’s continuing concern 

regarding whether the pro forma OATT 

adequately remedies undue 

discrimination, the Commission issued 

an NOI on September 16, 2005 36

seeking comments on appropriate 

reforms of the Order No. 888 pro forma 

OATT. In the NOI, the Commission 

expressed its preliminary view that 

reforms to the pro forma OATT and 

public utilities’ OATTs are necessary to 

avoid undue discrimination or 

preference in the provision of 

transmission service. The NOI sought 

comments on how best to accomplish 

the Commission’s goals, specifically 

with respect to enhancements that are 

needed to (1) Remedy any unduly 

discriminatory or preferential 

application of the pro forma OATT or 

(2) improve the clarity of the Order No. 

888 pro forma OATT and the individual 

public utility tariffs in order to more 

readily identify violations and facilitate 

compliance. 

24. The Commission received over 

4,000 pages of initial and reply 

comments on the NOI. Based on these 

comments, the comments submitted in 

response to the ATC NOI,37 our 

experience in implementing Order No. 

888, and the changes in the industry 

since we adopted it, the Commission 

proposed to reform the pro forma OATT 

in a number of ways. The Commission 

issued the NOPR on May 19, 2006 

proposing a number of reforms aimed at 

remedying undue discrimination in the 

provision of open access transmission 

service and improving the clarity of the 

pro forma OATT and the individual 

tariffs of transmission providers in order 

to more readily identify violations and 

facilitate compliance. The Commission 

received over 5,700 pages of initial and 

reply comments in response. In 

response to comments on the particular 

issue of redispatch and conditional firm 

service (discussed in more detail 

below), the Commission issued a Notice 

of Request for Supplemental Comments 

on November 15, 2006,38 that resulted 

in receipt of an additional 750 pages of 

comments. 

25. Based on this voluminous record, 

the Commission concludes that reform 

of the pro forma OATT and associated 

amendments to its regulations are 

necessary to reduce the potential for 

undue discrimination and provide 

clarity in the obligations of transmission 

providers and customers alike. We turn 

next to a more complete explanation of 

this need for reform. 

III. Need for Reform of Order No. 888 

A. Opportunities for Undue 

Discrimination Continue To Exist 

26. Although Order No. 888 has been 

successful in many important respects, 

the need for reform of the Order No. 888 

pro forma OATT has been apparent for 

some time. In 1999, the Commission 

held, in adopting Order No. 2000, that 

the pro forma OATT could not fully 

remedy undue discrimination because 

transmission providers retained both the 

incentive and the ability to discriminate 

against third parties, particularly in 

areas where the pro forma OATT left the 

transmission provider with significant 

discretion.39 The Commission made a 

similar finding in Order No. 2003,40

holding that opportunities for undue 

discrimination continue to exist in areas 

where the pro forma OATT leaves 

transmission providers with substantial 

discretion.41 The NOPR reaffirmed these 

findings, preliminarily concluding that 

opportunities for undue discrimination 

continue to exist in the provision of 

open access transmission service. The 

Commission therefore proposed a 

number of reforms to the pro forma 

OATT to address the opportunities and 

incentives transmission providers have 

to unduly discriminate. 

Comments 

27. Many commenters agree with the 

Commission that reforms to the pro 

forma OATT are needed because there 

continue to be both the opportunity and 

incentive for transmission providers to 

engage in undue discrimination.42

28. Several commenters offered 

examples of their experiences with 

transmission providers, where they 

believe transmission providers have 

acted in an unduly discriminatory 


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43See, e.g., Dow, Fayetteville, Occidental, and 

Williams. 44See also Southern Reply. 

45See, e.g., Entergy Reply, Progress Energy Reply, 

and Southern Reply. 

46E.g., Indicated New York Transmission 

Owners, ISO/RTO Council, and Northeast Utilities. 

fashion.43 Constellation claims that on 

multiple occasions it has been denied a 

transmission request when the 

transmission provider’s OASIS indicates 

that ATC is available, but Constellation 

had no effective and timely way to 

challenge that determination because of 

the ATC ‘‘black box.’’ Constellation 

states that given that its needs for 

transmission service are often near-term 

or immediate—e.g., to facilitate a loadserving obligation or wholesale 

transaction that must be consummated 

quickly—seeking redress at the 

Commission for improperly denied 

service generally is not time- or costeffective. Instead, Constellation asserts, 

it is often forced to accept the 

determination of the transmission 

provider that ATC is not available (even 

though its OASIS may indicate 

otherwise) and seek alternate 

transmission paths and/or products to 

consummate its transaction. 

29. Powerex also describes instances 

where a transmission provider has 

granted short-term firm point-to-point 

transmission service requests to 

transmission customers who have been 

allowed to remain in the queue, even 

when zero ATC is posted, in the hopes 

that a transmission provider’s OASIS 

site wrongly indicates zero ATC or will 

soon be updated. Powerex asserts that 

such practices clog the short-term pointto-point transmission queue with 

multiple requests and result in 

duplicative requests for service that 

reflect customers’ attempts to secure 

service, rather than the actual quantity 

of service needed. Moreover, Powerex 

argues, transmission provider discretion 

in this area and the lack of transparency 

raise customer concerns about 

preferential treatment. 

30. Occidental claims that it has firsthand experience with a vertically 

integrated transmission provider that, 

despite having an OATT, appears to 

have persistently used its transmission 

system to preferentially benefit its 

merchant function. Similarly, Williams 

alleges that its interests have been 

consistently and significantly 

compromised by the discretion afforded 

transmission providers in the 

interpretation of the OATT and the lack 

of transparency in requesting, 

scheduling and interrupting of 

transmission service. 

31. Other commenters, however, 

argue that the Commission’s proposed 

reforms are based on unsupported 

allegations of undue discrimination. EEI 

maintains that any opportunities to 

engage in undue discrimination have 

been largely mitigated by current 

regulatory policies and changes in the 

industry. EEI explains that, unlike the 

situation that existed when the 

Commission enacted Order No. 888, 

much of the country’s transmission 

facilities are now under the control of 

RTOs and ISOs. In addition, EEI states, 

other transmission providers have 

transferred (or are in the process of 

transferring) the administration of their 

OATTs and OASIS functions to 

independent transmission service 

coordinators. Even among the 

transmission providers who have taken 

neither of those steps, EEI argues that 

the open access requirements of Order 

No. 888 and the Standards of Conduct 

of Order Nos. 889 and 2004 have largely 

eliminated the ability of transmission 

providers to engage in undue 

discrimination in the provision of 

transmission service.44 In addition, EEI 

states, the Commission’s expanded civil 

penalty authority added to the FPA by 

EPAct 2005 gives the Commission a 

powerful tool that will further eliminate 

any remaining incentive of transmission 

providers to engage in undue 

discrimination in the provision of 

transmission service. Therefore, EEI 

asserts, any modifications to the OATT 

should be narrowly tailored to address 

the perceptions of residual undue 

discrimination. To the extent that such 

perceptions exist, however, Community 

Power Alliance states that, in the 

absence of concrete record evidence, 

they are just that—perceptions. 

32. Although Duke strongly supports, 

as a policy matter, OATT reforms that 

will eliminate the perception that undue 

discrimination is possible and/or likely, 

Duke argues that the FPA does not 

provide the Commission the authority to 

remedy mere ‘‘opportunities’’ to 

discriminate. Duke states that, in some 

cases, the Commission is attempting to 

remedy an opportunity for undue 

discrimination that does not exist or is 

proposing to impose a remedy that does 

not actually remedy the perceived 

opportunity. Duke notes, however, that 

some OATT terms and conditions are 

subject to multiple interpretations and 

argues that the Commission can, and 

should, justify the OATT reforms 

proposed in the NOPR as reforms 

needed to provide clarity to existing 

policies. 

33. With regard to specific allegations 

made by commenters, several 

transmission providers respond that the 

examples given by transmission 

customers do not illustrate instances of 

undue discrimination. Rather, they 

assert, these examples demonstrate the 

transmission customers’ lack of 

understanding of the OATT 

requirements, and the data available on 

OASIS.45

34. New Mexico Attorney General 

argues that the traditional Stateregulated, vertically-integrated cost-ofservice world is not in need of reform. 

Contrary to the ‘‘conspiracy theorists’’

who argue that utilities have an 

incentive to engage in undue 

discrimination and preference in 

transmission services, New Mexico 

Attorney General asserts that utilities 

have an incentive to maximize 

throughput and revenue between Statelevel rate cases because incremental 

transmission revenue is not deducted 

from the State-jurisdictional retail 

revenues between rate cases. Similarly, 

Southern, in its reply comments, asserts 

that broad claims of undue 

discrimination fail to take into 

consideration that vertically-integrated 

utilities have more of an incentive to act 

appropriately than do independent 

utilities because the former have more 

to lose (e.g., loss of market-based rates, 

state prudence reviews of costs, etc.) if 

they are found to have engaged in 

wrong-doing. Southern states that any 

OATT revisions ultimately adopted by 

the Commission must be reasonably 

tailored to address an identified 

problem or to provide a specific 

improvement. 

35. Other commenters argue that the 

Commission’s focus should be on 

transmission providers in non-organized 

markets, arguing that remaining 

concerns about undue discrimination 

have already been addressed in the 

world of ISOs and RTOs.46 According to 

ISO/RTO Council, this proceeding 

provides an opportunity for the 

Commission to harmonize the worlds of 

organized and non-organized markets in 

a manner that encourages competition, 

promotes non-discriminatory access, 

and maximizes the flow of electricity 

across various ISO/RTO and non-ISO/ 

RTO regions. ISO/RTO Council states 

that, in the existing regulatory 

environment, a utility that is not a 

member of an ISO or RTO can sell into, 

or purchase from, an ISO or RTO market 

even though the non-ISO/RTO utility 

operates under tariff rules that are less 

open and transparent, particularly in 

terms of access to generation resources 

and pricing/system information, than 

their competitors that belong to an ISO 

or RTO. Such asymmetry, ISO/RTO 

Council argues, operates as an 


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47Order No. 888 at 31,682. 

48See, e.g., Order No. 2003 at P 11–12. 

49See, e.g., Potomac Economics, Ltd., 2004 State 

of the Market Report: Midwest ISO at 30–31, 34–35 

(Jun. 2005), http://www.midwestmarket.org/ 

publish/Document/2b8a32_103ef711180_-7bf20a

48324a/2004%20MISO%20SOM%20Report.pdf?

action=download&_property=Attachment 

(explaining that the queuing process, by giving 

customers the opportunity to submit multiple 

requests for service, provides a low- or no-cost 

option that restricts other customers’ access to 

congested interfaces, and the scheduling process, by 

allowing customers to leave transmission requests 

unconfirmed, provides a free option that may invite 

hoarding or result in underutilized capacity). 

50 824 F.2d 981 (D.C. Cir. 1987) (AGD). 

51 15 U.S.C. 717. 

52TAPS v. FERC, 225 F.3d at 667, 688; National 

Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C. 

Cir. 2006) (National Fuel). 

53 824 F.2d at 1008. 

54See, e.g., Duke and EEI. 

impediment to fair and nondiscriminatory transmission access and 

management of grid congestion. 

36. ISO/RTO Council states that its 

members do not seek to impose their 

market designs on the rest of the nation. 

At the same time, ISO/RTO Council 

argues that meaningful reform should 

ensure a level of transparency (of both 

price and the dispatch utilized by nonISO/RTO vertically-integrated entities) 

in regions without an ISO or RTO that 

can assist the flow of electricity and 

enhance reliability and planning in both 

ISO/RTO and non-ISO/RTO regions. 

37. Exelon urges the Commission to 

hold the transmission providers outside 

ISOs or RTOs to the same standard of 

non-discrimination that exists within 

those organizations. Further, MISO/PJM 

States argue that in order to achieve 

some level of independence in non-RTO 

regions, non-independent transmission 

providers should be encouraged to turn 

over operational control of their 

transmission systems to an independent 

coordinator of transmission whose 

functions would include security 

coordination, determination of ATC, 

granting of transmission service and 

oversight for transmission planning. 

38. Finally, EPSA suggests that the 

Commission establish a one-year review 

period for the reformed pro forma 

OATT. EPSA urges the Commission to 

revisit this Final Rule after one year of 

operation under the reformed pro forma 

OATT to ensure that the revisions 

adopted here do, in fact, protect against 

non-discriminatory or preferential 

behavior by transmission providers. 

NRECA responds that, after this 

comprehensive rulemaking process, 

there is simply no need for another 

major look at the OATT in one year. 

Moreover, NRECA states, one year is 

likely too short a period for the 

Commission and industry participants 

to fully appreciate all of the 

consequences of those elements of 

OATT reform resulting from this 

proceeding. At the same time, NRECA 

agrees that the Commission should 

carefully monitor implementation of the 

reformed OATT. This monitoring, 

NRECA states, must be an ongoing 

process and cannot wait a year to begin. 

Commission Determination 

39. The Commission concludes that 

reforms are needed to address 

deficiencies in the pro forma OATT that 

have become apparent since 1996, by 

limiting remaining opportunities for 

undue discrimination. As the 

Commission found in Order No. 888, it 

is in the economic self-interest of 

transmission monopolists, particularly 

those with high-cost generation assets, 

to deny transmission or to offer 

transmission on a basis that is inferior 

to that which they provide to 

themselves.47 Such an incentive can 

lead to unduly discriminatory behavior 

against third parties, particularly if 

public utilities have unnecessarily 

broad discretion in the application of 

their tariffs. This discretion also can 

create problems for transmission 

providers seeking to comply with our 

regulations in good faith because so 

many issues are left for their 

interpretation, thereby increasing the 

possibility of disputes with 

transmission customers and 

enforcement actions by the 

Commission.48 Transmission customers 

also have found ways to use the tariffs 

to their own advantage, particularly in 

the scheduling and queuing processes.49

40. As some commenters note, 

opportunities for undue discrimination 

persist, particularly in areas where the 

pro forma OATT leaves the 

transmission provider with substantial 

discretion. The Commission has a 

responsibility under section 206 of the 

FPA to remedy undue discrimination. 

Indeed, the court concluded in 

Associated Gas Distributors v. FERC,50

that, like the Natural Gas Act,51 the FPA 

‘‘fairly bristles’’ with concern over 

undue discrimination. Based on AGD, 

the Commission determined in Order 

No. 888 that: 

The Commission has a mandate under 

sections 205 and 206 of the FPA to ensure 

that, with respect to any transmission in 

interstate commerce or any sale of electric 

energy for resale in interstate commerce by 

a public utility, no person is subject to any 

undue prejudice or disadvantage. We must 

determine whether any rule, regulation, 

practice or contract affecting rates for such 

transmission or sale for resale is unduly 

discriminatory or preferential, and must 

prevent those contracts and practices that do 

not meet this standard. * * * AGD 

demonstrates that our remedial power is very 

broad and includes the ability to order 

industry-wide non-discriminatory open 

access as a remedy for undue discrimination. 

Order No. 888 at 31,669. Through this 

Final Rule, the Commission exercises 

that remedial authority again to limit 

further opportunities for undue 

discrimination, by minimizing areas of 

discretion, addressing ambiguities and 

clarifying various aspects of the pro 

forma OATT. 

41. We disagree with commenters 

who assert that the Commission is 

relying on unsubstantiated allegations of 

discriminatory conduct to justify OATT 

reform. The courts have made clear that 

the Commission need not make specific 

factual findings of discrimination in 

order to promulgate a generic rule to 

eliminate undue discrimination.52 In 

AGD, the court explained that the 

promulgation of generic rate criteria 

involves the determination of policy 

goals and the selection of the means to 

achieve them and that courts do not 

insist on empirical data for every 

proposition upon which the selection 

depends: ‘‘[a]gencies do not need to 

conduct experiments in order to rely on 

the prediction that an unsupported 

stone will fall.’’ 53 During this multi-year 

proceeding, the Commission has 

received many comments arguing that 

commenters have either experienced or 

perceived that they have experienced 

unduly discriminatory conduct by 

transmission providers. Even 

transmission providers have 

acknowledged that there is a continuing 

perception that there is the opportunity 

for them to unduly discriminate against 

their competitors and, accordingly, they 

state their support for our reform 

effort.54 Moreover, it is undisputed that 

the existing pro forma OATT provides 

wide discretion in implementing some 

of its basic requirements, such as the 

assessment of whether sufficient ATC 

exists to grant third party access to the 

grid and the manner in which new 

facilities are planned to satisfy third 

party needs. This wide discretion, when 

coupled with a transmission provider’s 

incentive to discriminate, creates 

opportunities for discrimination under 

the pro forma OATT. We have an 

obligation under section 206 to remedy 

that discrimination. 

42. It is thus clear to us that, 

notwithstanding the Commission’s 

efforts in Order No. 888, opportunities 

to engage in undue discrimination can 

and will persist unless the existing pro 

forma OATT is reformed. We therefore 

exercise our broad remedial authority 

today to limit these remaining 


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opportunities for undue discrimination. 

The Commission concludes that any 

additional costs incurred by 

transmission providers to implement 

the reforms required in this Final Rule 

are fully justified by the need to ensure 

open, transparent and nondiscriminatory access to transmission 

service. We also believe it is appropriate 

to adopt these reforms by rulemaking, 

rather than rely on complaints filed by 

transmission customers or other parties. 

Case-by-case application of the reforms 

adopted in this Final Rule would be 

inappropriate since the most 

fundamental problems addressed here 

arise from deficiencies in the pro forma 

OATT itself, not simply the 

implementation of the pro forma OATT 

by a few transmission providers. Also, 

we decline to establish a one-year 

review period for the reformed pro 

forma OATT, as EPSA recommends. 

The Commission will continue to 

actively monitor compliance with its 

orders and, as necessary, institute 

further proceedings to meet its statutory 

obligation to remedy undue 

discrimination. 

43. The Commission will not catalog 

each and every basis for its reform of the 

pro forma OATT in this section. Rather, 

we identify the bases for some of the 

most fundamental reforms herein and, 

in addition, we explain in each 

individual section of the Final Rule the 

inadequacies of the existing pro forma 

OATT provisions being addressed there 

and the reasons why our reforms are 

necessary to remedy undue 

discrimination or otherwise provide for 

rates, terms and conditions of service 

under the pro forma OATT that are just 

and reasonable. 

B. Lack of Transparency Undermines 

Confidence in Open Access and 

Impedes Enforcement of Open Access 

Requirements 

44. Following the issuance of the NOI, 

the Commission received a number of 

comments asserting that increased 

transparency would aid transmission 

customers in their participation in the 

wholesale market. A common theme in 

the comments was that a lack of 

transparency could lead to claims of 

discrimination and could make such 

claims more difficult to resolve. 

Commenters urged the Commission to 

improve transparency in a number of 

areas, particularly the evaluation of ATC 

and the planning of the transmission 

system, as well as the processing of 

transmission service requests and 

studies. 

45. In the NOPR, the Commission 

agreed that a lack of transparency both 

increases the potential for undue 

discrimination and makes it more 

difficult to detect. The Commission 

reasoned that this lack of sufficient 

transparency was caused in part by 

inadequate compliance with the existing 

OASIS regulations and in part by 

inadequate transparency requirements. 

The Commission stated that the 

proposed reforms were intended to 

address both elements of the problem in 

an effort to increase confidence in open 

access tariffs and to facilitate 

compliance with the Commission’s 

regulations and its enforcement of them. 

Comments 

46. Williams states that its interests 

have been consistently and significantly 

compromised by the discretion afforded 

transmission providers in the 

interpretation of the OATT and the lack 

of transparency in requesting, 

scheduling and interrupting of 

transmission service. According to 

Williams, simply being told that service 

is being curtailed for reliability 

purposes under opaque local 

procedures, in the absence of a NERC 

Transmission Loading Relief (TLR) 

event, leaves market participants 

suffering the consequences without 

knowing on what basis the decision was 

reached, and without assurance that the 

decision was made in a nondiscriminatory manner. Ultimately, 

Williams adds, the lack of transparency 

and latitude taken by the transmission 

provider to determine which requests 

for service are confirmed or denied and 

which are curtailed or interrupted in 

real time frustrates the Commission’s 

goal of preventing undue discrimination 

and preference in the provision of 

transmission service. Furthermore, 

Williams states, the same lack of 

transparency exists around the opaque 

processes utilized, assumptions made, 

and basis on which the results of 

transmission planning studies are 

conducted to grant or deny requests for 

service. 

47. APPA agrees that additional 

transparency in the administration of 

public utility transmission providers’

OATTs will be of material assistance to 

both the Commission and transmission 

customers. However, APPA argues that 

the Commission must go beyond 

increasing transparency in the 

administration of public utility 

transmission providers’ OATTs. 

According to APPA, more transparency 

will not change the basic industry 

paradigm with transmission customers 

depending on monopoly transmission 

providers for service. In APPA’s view, 

customers are often reluctant to file 

complaints or bring problems to the 

Commission’s attention because they 

depend on their transmission providers’

systems for the vital services they need 

to serve their loads. APPA argues that 

the Commission not only has an 

obligation to act to remedy undue 

discrimination when it sees it, but also 

has an affirmative duty to look for it. 

According to APPA, the Commission 

must continue to actively regulate the 

transmission services that public utility 

transmission providers offer, even if full 

transparency is achieved through the 

revisions to the OATT implemented in 

the instant docket. 

48. EPSA agrees that greater 

transparency will help enable market 

participants and the Commission to 

monitor and audit the behavior of 

transmission providers. EPSA states that 

the several ‘‘black boxes’’ shielding 

discriminatory transmission service 

over the past ten years must be opened. 

However, EPSA argues, there must be 

meaningful clarity and obligations set 

out in the rules and OATT 

requirements—transparency simply for 

the sake of knowing why transmission 

service has been denied only 

illuminates a ‘‘bridge to nowhere’’ and 

fails to satisfy the Federal Power Act. 

49. Entergy also supports the 

Commission’s efforts to provide greater 

clarity in the rights and obligations of 

transmission providers and 

transmission customers under the 

OATT. According to Entergy, many of 

the improvements proposed by the 

Commission will reduce the likelihood 

of disputes and promote greater 

confidence on the part of customers that 

they are being treated fairly. Entergy 

states that, while it recognizes that the 

lack of clarity makes it difficult for the 

Commission to detect instances of noncompliance by transmission providers, 

Entergy also believes that this lack of 

clarity often makes it easier for 

transmission customers to convert every 

practice or policy into a claim of 

discrimination or other misconduct. 

50. Although not convinced that there 

is a compelling need for increased 

transparency since transmission 

providers are already required to 

disclose voluminous amounts of 

information, Southern states that it 

recognizes that some reforms in the 

availability of information may be 

advantageous. However, Southern 

asserts, providing additional 

transparency must not simply impose 

additional reporting requirements; any 

such transparency-related reforms 

should be made after taking into 

consideration the extent and type of 

data and information that is already 

provided. 


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55Eric Hirst, U.S. Transmission Capacity: Present 

Status and Future Prospects (Aug. 2004), http:// 

www.eei.org/industry_issues/energy_infrastructure/ 

transmission/USTransCapacity10–18–04.pdf 

(Present Status and Future Prospects). 

56Present Status and Future Prospects at v. 

57Brendan Kirby (Oak Ridge National Laboratory, 

U.S. Department of Energy), Barriers to 

Transmission Investment, Technical Conference 

Presentation, (Docket No. AD05–5–000) (April 22, 

2005). 

Commission Determination 

51. The Commission concludes that 

inadequate transparency requirements, 

combined with inadequate compliance 

with existing OASIS regulations, 

increases the opportunities for undue 

discrimination under the pro forma 

OATT and makes instances of undue 

discrimination more difficult to detect. 

We find that the reforms we adopt in 

this Final Rule will improve 

transparency in the OATT, reduce 

opportunities for undue discrimination, 

and increase our ability to detect undue 

discrimination. 

C. Congestion and Inadequate 

Infrastructure Development Impede 

Customers’ Use of the Grid 

52. The Commission noted in the 

NOPR that the ability and incentive to 

discriminate increases as the 

transmission system becomes more 

congested. The Commission observed 

that the pro forma OATT contained only 

minimal requirements regarding 

transmission planning, which have 

proven to be inadequate as the Nation 

faces insufficient transmission 

investment in many areas. The 

Commission preliminarily concluded 

that the inadequacy of the existing 

obligation to conduct transmission 

system planning, coupled with the lack 

of transparency surrounding system 

planning generally, required reform of 

the pro forma OATT to ensure that 

transmission infrastructure is 

constructed on a nondiscriminatory 

basis and is otherwise sufficient to 

support reliable and economic service to 

all eligible customers. The Commission 

therefore proposed to require public 

utilities to engage in an open and 

transparent planning process at both the 

local and regional levels. 

Comments 

53. APPA agrees that the lack of 

adequate transmission infrastructure is 

one of the core problems facing the 

electric utility industry. APPA supports 

revisions to the pro forma OATT to 

enhance and improve transmission 

planning on both an individual system 

and regional basis. Several commenters 

go further, arguing that the proposed 

reforms are insufficient and urging the 

Commission to more strongly encourage 

infrastructure development. EPSA 

asserts that successful implementation 

of the Congressional policy in favor of 

wholesale competition and State 

policies in favor of competitive 

procurement is frustrated by the lack of 

sufficient open access to the 

transmission grid. According to EPSA, 

new power plant investment is highly 

unlikely to occur, except by the 

transmission provider or its affiliate on 

a ‘‘sole source’’ or ‘‘no bid’’ basis 

(despite Federal and State policies to 

the contrary), if unaffiliated suppliers 

cannot effectively and efficiently obtain 

transmission service. EPSA argues that 

failure to boldly reform the 

Commission’s open access transmission 

rules at this critical juncture would 

effectively hand an undeserved victory 

to the very transmission providers who, 

by the Commission’s own findings, have 

the motive and the opportunity to 

discriminate. International 

Transmission argues that tariff reform is 

no substitute for prudent investment in 

the transmission infrastructure needed 

to increase the underlying physical 

capability of the transmission system. 

54. On the other hand, some 

commenters dispute the Commission’s 

assertion in the NOPR that verticallyintegrated utilities operating in nonRTO regions have an incentive to 

discriminate and, therefore, are not 

adequately expanding the transmission 

grid to accommodate new entry by more 

efficient competitors. New Mexico 

Attorney General argues that verticallyintegrated utilities operating under the 

traditional rate-base, rate-of-return 

model of regulation in fact have been 

historically criticized for having 

incentives to overbuild. New Mexico 

Attorney General asserts that most 

transmission projects are in reality 

derailed by strong ‘‘NIMBY’’ opposition 

to the actual siting of transmission lines. 

Another countervailing factor to the 

utility’s incentive to overbuild, in New 

Mexico Attorney General’s view, is the 

fact that State regulators attempt to limit 

capacity investment to reasonable levels 

only necessary to serve native load. 

55. Southern states that the 

Commission’s assertion in the NOPR 

that vertically-integrated utilities do not 

have an incentive to expand the grid 

overlooks the fact that many such 

utilities are under State legal duties to 

procure generation supplies through 

open, non-discriminatory requests for 

proposals, with the winners of those 

requests for proposals often being 

competitors of the vertically-integrated 

utility. Southern maintains that the 

winning competitive generation is then 

integrated into the host utility’s 

transmission system and dispatch, and 

the transmission system is expanded to 

ensure the deliverability of this 

competitive generation. Furthermore, 

Southern states, a competitive generator 

can also have the output of its generator 

planned into the transmission 

provider’s system if it takes long-term 

firm service under the OATT, with the 

transmission provider then being under 

a legal duty to expand its transmission 

system accordingly. Southern notes that 

it alone has invested $3.2 billion in 

transmission over the past decade and 

plans to invest another $2.8 billion over 

the next five years (2006–2010). 

56. Community Power Alliance also 

argues that the Commission’s own June 

2005 ‘‘State of the Markets Report’’

contradicts the Commission’s assertion 

that vertically-integrated utilities do not 

have the proper incentives to expand 

the grid. Community Power Alliance 

contends that this report shows that the 

amount of transmission investments 

made in the non-RTO regions, where 

vertically-integrated utilities typically 

operate, substantially exceeds the 

amount of transmission investments 

made in RTO regions. 

Commission Determination 

57. The Commission concludes that 

reforms are needed to ensure that 

transmission infrastructure is evaluated, 

and if needed, constructed on a 

nondiscriminatory basis and is 

otherwise sufficient to support reliable 

and economic service to all eligible 

customers. As noted above, verticallyintegrated utilities do not have an 

incentive to expand the grid to 

accommodate new entries or to facilitate 

the dispatch of more efficient 

competitors. Despite this, the existing 

pro forma OATT contains very few 

requirements regarding how 

transmission planning should be 

conducted to ensure that undue 

discrimination does not occur. 

58. Our concern over this flaw is 

heightened by the critical need for new 

transmission infrastructure in this 

Nation. As the Commission explained in 

the NOPR, transmission capacity is 

being constructed at a much slower rate 

than the rate of increase in customer 

demand, with transmission capacity per 

MW of peak demand declining at an 

average rate of 2.1 percent per year 

during the period 1992 to 2002.55 The 

projections suggest that this trend will 

continue through 2012.56 As a result, 

there has been a significant decrease in 

transmission capacity relative to load in 

every NERC region.57 In light of this 

trend, there is a compelling need to 

build new transmission and respond to 

increasing demand through other 


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58Energy Policy Act of 2005: Hearings before the 

Subcommittee on Energy and Air Quality of the 

House Committee on Energy and Commerce, 109th 

Congress, First Sess. (2005) (Prepared statement of 

Thomas R. Kuhn, President of EEI). 

59Present Status and Future Prospects at v. 

60U.S. Department of Energy, National 

Transmission Grid Study at 11, 16–17 (May 2002), 

available at http://www.ferc.gov/industries/electric/ 

indus-act/transmission-grid.pdf. To conduct this 

study, DOE estimated the benefits of interregional 

wholesale power markets using the Policy Office 

Electricity Modeling System (POEMS). POEMS is a 

national energy model designed specifically to 

examine the impacts of electricity restructuring. 

The model includes economic, regional, and 

temporal detail that is needed to analyze the 

economics of interregional trade. In the first step of 

the study, DOE used POEMS to examine the cost 

reductions that would occur if increased electricity 

transfers across congested paths were allowed in 

these four regions, assuming generators bid their 

marginal costs. Under this assumption, consumer 

costs declined by $157 million per year. In the 

second step, DOE calculated the increase in 

congestion costs under the assumption that 

generators bid above their marginal operating costs 

when supplies are tight and additional electricity 

cannot be imported. The price spikes were assumed 

to occur during hours when at least one 

transmission link into a sub-region was congested 

and demand was greater than 90 percent of peak 

demand. When prices spike an additional $50 per 

MWh (above the price predicted when generators 

bid their marginal operating cost) during these 

periods, congestion costs nearly double to $300 

million. 

61 Id. at xi and ii. 

62U.S. Department of Energy, National Electric 

Transmission Congestion Study, Executive 

Summary at 2 (August 2006), available at http:// 

www.ferc.gov/industries/electric/indus-act/doecongestion-study-2006.pdf. 63Order No. 888 at 31,794 n.610. 

means. EEI estimates that capital 

spending must increase by 25 percent, 

from $4 billion annually to $5 billion 

annually, to ensure system reliability 

and to accommodate wholesale electric 

markets.58 The legacy systems 

constructed by vertically-integrated 

utilities prior to the adoption of Order 

No. 888 support ‘‘only limited amounts 

of inter-regional power flows and 

transactions. Thus, existing systems 

cannot fully support all of society’s 

goals for a modern electric-power 

system.’’ 59

59. Expansion of the transmission 

system, as well as more efficient use of 

the grid, will alleviate the growth of 

congestion in most regions of the 

country. Transmission congestion has 

created fairly small local load pockets in 

primarily urban areas, e.g., New York 

City, Long Island, Boston, parts of 

Connecticut, and the San Francisco Bay 

Area. Other load pocket concerns have 

arisen in parts of northern Virginia, and 

various load centers in SPP. Still other 

constraints are more regional in scope: 

from the Midwest to the Mid-Atlantic, 

from the Midwest to TVA, into and 

within California, from TVA and 

Southern into Entergy, from MidAmerica Interconnected Network into 

Wisconsin-Upper Michigan Systems, 

and into Florida. 

60. Transmission congestion can have 

significant cost impacts on consumers. 

In 2002, DOE issued a study estimating 

the costs of congestion in four U.S. 

regions: California, PJM, New York and 

New England.60 DOE found that, despite 

the overall savings of wholesale 

electricity markets that lowered 

consumers’ electricity bills by nearly 

$13 billion annually, interregional 

transmission congestion cost consumers 

hundreds of millions of dollars 

annually. DOE concluded that relieving 

bottlenecks in these four regions alone 

could save consumers about $500 

million annually.61 In 2006, DOE 

released another study identifying two 

areas of the country with severe existing 

or growing congestion problems: the 

Atlantic coastal area from metropolitan 

New York southward through Northern 

Virginia, and Southern California.62

61. The decline in transmission 

investment and increase in transmission 

congestion underscore our concerns 

over inadequate planning provisions of 

the existing pro forma OATT. The 

existing pro forma OATT, as indicated 

above, contains very little specificity 

regarding how transmission planning 

should be conducted, how customers’

needs are incorporated into that process, 

and what information is publicly 

available regarding the transmission 

providers’ assumptions, criteria and 

data used in the planning process. 

These inadequacies are sufficiently 

severe, standing alone, to merit reform 

of the OATT. However, they are of even 

greater concern given the current state 

of the transmission grid. With 

inadequate levels of investment in the 

grid and increasing transmission 

congestion, customers’ ability to access 

alternatives to the transmission 

provider’s resources is limited. It is 

therefore imperative for the Commission 

to ensure that the planning process 

under each transmission provider’s 

OATT is sufficient to prevent undue 

discrimination and transparent enough 

to detect any remaining instances of 

undue discrimination. We have done so 

in the reforms adopted and explained in 

section V.B. 

D. A Consistent Method of Measuring 

ATC Is Needed 

62. Another area in which 

transmission providers have significant 

discretion under the pro forma OATT is 

the calculation of ATC. While Order No. 

888 obligated each public utility to 

calculate the amount of transfer 

capability on its system available for 

sale to third parties, the Commission 

did not standardize the methodology for 

calculating ATC, nor did it impose any 

specific requirements regarding the 

disclosure of the methodologies used by 

each transmission provider.63 As a 

result, there are a variety of ATC 

calculation methodologies in use today 

and very few clear rules governing their 

use. Moreover, there is often very little 

transparency about the nature of these 

calculations, given that many 

transmission providers have filed only 

summary explanations of their ATC 

methodologies in Attachment C to their 

OATTs. 

63. In the NOPR, the Commission 

noted that, although the industry has 

sought to pursue greater consistency in 

ATC calculations through existing 

NERC processes, these efforts to date 

have been largely unsuccessful. The 

Commission expressed its preliminary 

determination that the lack of a 

consistent, industry-wide methodology 

for calculating ATC gives transmission 

providers the ability and the 

opportunity to unduly discriminate 

against third parties. The Commission 

therefore proposed a number of reforms 

to the process of calculating ATC to 

provide clarity and transparency to 

users of the grid. 

Comments 

64. As discussed further in section 

V.A below, most commenters support 

the Commission’s goal of requiring 

greater consistency in the manner in 

which ATC is calculated and additional 

transparency of ATC calculations. 

Commenters generally favor the 

Commission’s proposal to increase 

consistency in the calculation of ATC, 

including consistent definitions of its 

components, data inputs, modeling 

assumptions, and data exchange and 

coordination protocols. For example, 

Exelon argues that each ATC component 

should be used in the same manner for 

all purposes (e.g., granting transmission 

service to third parties or for the 

transmission provider’s own network 

load). Some commenters assert that 

industry-wide standardization of ATC 

calculation might not be possible and 

that the Commission should consider 

interconnection-wide, regional or even 

sub-regional standardization. Others 

suggest allowing flexibility in order to 

capture differences in system operation, 

usage, market operations and topology. 

65. At the technical conference 

organized in this proceeding on October 

12, 2006 (October 12 Technical 

Conference), the entire panel agreed that 

definitions must be consistent and a 

panelist representing Constellation 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12277 

64Transcript of October 12 Technical Conference 

at 149–50, available at Preventing Undue 

Discrimination and Preference in Transmission 

Service, Technical Conference (Docket No. RM05–

25–000). 

65 Id. at 125–50. 

66Energy imbalance charges, including penalties 

on some systems, are imposed on a transmission 

customer when the amount of energy scheduled for 

delivery to the transmission grid does not equal the 

amount of energy withdrawn by that customer. 

Generator imbalance charges are levied on 

generators for deviations between the amount of 

energy they schedule and the amount they actually 

deliver to the grid. 

asserted that broad differences in the 

core definitions of the ATC calculation 

are neither rational nor explainable.64

NERC, however, recognized that the 

goal of achieving consistency may not 

mean that a single ATC methodology is 

required.65 NERC explained that 

consistency can be achieved with a 

limited number of methodologies if the 

requirements of those methodologies are 

properly coordinated and 

communicated. 

66. Numerous commenters support 

the Commission’s proposals to increase 

transparency in the manner in which 

transmission providers derive ATC, 

including greater OASIS posting. 

Commenters opposing the transparencyrelated reforms focus on the 

Commission’s proposal to require the 

posting of narratives on OASIS 

explaining reasons for changes in 

monthly and yearly ATC values on 

constrained paths. They argue that such 

a requirement would be too burdensome 

and would not provide customers with 

any significant new information. 

67. Several commenters believe that 

making substantial ATC calculation and 

modeling data transparent will 

compromise Critical Energy 

Infrastructure Information (CEII) but 

provide suggestions for resolving the 

issue. Others express concern that the 

data required for posting on OASIS is 

not CEII but commercially sensitive. 

Finally, commenters provide 

suggestions regarding the requirement to 

post metrics on OASIS related to the 

provision of transmission service under 

the pro forma OATT, including various 

additional metrics the Commission 

should consider. Others state that this 

information is already available on 

OASIS. 

Commission Determination 

68. We find that the lack of a 

consistent and transparent methodology 

for calculating ATC gives transmission 

providers the ability and opportunity to 

unduly discriminate in the provision of 

open access transmission service. There 

are few clear rules respecting ATC 

calculation, and transmission providers 

retain unnecessarily broad discretion in 

this area. This resulting discretion is a 

significant problem because calculation 

of ATC, which varies greatly depending 

on the criteria and assumptions used, 

may allow the transmission provider to 

discriminate in subtle ways against its 

competitors. On systems where 

transmission capacity is congested, this 

lack of consistency, coupled with a lack 

of transparency, is of heightened 

importance and has led to recurring 

disputes over whether the transmission 

provider is exercising its discretion to 

discriminate against its competitors. 

This discretion also hampers the 

detection of undue discrimination and, 

thereby, undermines the Commission’s 

ability to enforce the general 

requirement in Order No. 888 that 

transmission service be provided on a 

not unduly discriminatory basis. 

69. As discussed more fully below in 

section V.AIII.D, this Final Rule adopts 

a number of reforms that address the 

potential for remaining undue 

discrimination in the determination of 

ATC by requiring consistency in how 

ATC is evaluated, as well as providing 

greater transparency about how a 

transmission provider calculates and 

allocates ATC. 

E. Discriminatory Pricing of Imbalances 

70. Order No. 888 focused primarily 

on the adoption of non-rate terms and 

conditions of service, rather than 

instituting broad reform of the 

Commission’s transmission pricing 

policies. Consistent with this focus, the 

Commission did not propose broad 

transmission pricing reform in the 

NOPR, but rather focused on instances 

where current pricing practices under 

the pro forma OATT may no longer be 

sufficient to remedy undue 

discrimination or ensure just and 

reasonable rates. One significant reform 

proposed in the NOPR related to charges 

for imbalance energy. The Commission 

preliminarily found that the existing 

policies provide wide discretion in the 

development of these charges and hence 

the potential for undue discrimination. 

The Commission therefore proposed 

certain principles to remedy that 

potential and sought comment on 

whether a specific imbalance pricing 

method would be appropriate. 

Comments 

71. In general, transmission customers 

complain about the level and scope of 

energy and generator imbalance charges 

that are levied under the pro forma 

OATT and under individual 

interconnection agreements.66

Customers complain that energy 

imbalance charges are excessive and not 

related to the actual costs incurred by 

transmission providers. They also argue 

that the inconsistency between these 

charges in different control areas is 

unnecessary, and that other means of 

compensating the transmission 

provider, such as return-in-kind, should 

be considered. Generators likewise 

complain that generator imbalance 

charges are excessive, that transmission 

providers refuse to credit generators 

with the revenues resulting from 

imbalance penalties that are collected, 

and that transmission providers prevent 

unaffiliated generators from purchasing 

or self-supplying generator imbalance 

services. In addition, owners of 

intermittent resources complain that 

generator imbalance charges, which are 

imposed to provide an incentive for 

generators to schedule accurately, are 

inappropriate given their lack of control 

and ability to cure deviations. 

Commission Determination 

72. The Commission agrees that 

imbalance charges should provide 

appropriate incentives to keep 

schedules accurate without being 

excessive. We also find that consistency 

in imbalance charges, both between and 

among energy and generator imbalances, 

is preferable to the wide variety of 

imbalance provisions in place today. All 

imbalances have the same net effect on 

the transmission system in that they 

require other generation to be ramped 

up or down to compensate for the 

imbalance. As such, the Commission 

adopts two pro forma OATT provisions 

(Schedule 4 for energy imbalances and 

Schedule 9 for generator imbalances) 

based on a tiered structure similar to the 

imbalance provision used by 

Bonneville, as described further below. 

Such an approach recognizes the link 

between escalating deviations and 

potential reliability impacts on the 

system while keeping imbalance charges 

closely related to incremental costs. The 

Commission finds, however, that 

intermittent resources should be exempt 

from the highest-tier deviation band. We 

also require transmission providers to 

credit to all non-offending transmission 

customers the revenues they collect in 

excess of incremental costs. 

F. Redispatch/Conditional Firm 

73. In the NOPR, the Commission 

examined whether existing methods for 

evaluating requests for long-term firm 

point-to-point service continue to be 

just and reasonable. When a 

transmission provider considers a new 

resource to serve native load, the 

transmission provider does not 

eliminate an otherwise economic option 

because the resource may not be 


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67Although pro forma OATT section 13.5 refers 

to ‘‘redispatch,’’ we refer to it here as ‘‘planning 

redispatch’’ to distinguish it from the reliability 

redispatch provisions in the network integration 

transmission service sections of the pro forma 

OATT. See infra notes 552 and 557. 

68EPAct 2005 sec. 1241 (to be codified at section 

219 of the FPA, 16 U.S.C. 824s). The Commission 

has issued a Final Rule implementing such an 

incentive rate program. See Order Nos. 679 and 

679–A. 

69FPA Sec. 219(b)(1). 

70EPAct 2005 sec. 1223 (to be codified at 42 

U.S.C. 16442). 

71EPAct 2005 sec. 1221(a) (to be codified at 

section 216 of the FPA, 16 U.S.C. 824p). The 

Commission implemented new regulations in 

accordance with this section to establish filing 

requirements and procedures for entities seeking to 

construct electric transmission facilities in Order 

No. 689. 

deliverable during a few hours of the 

year. For transmission customers, 

however, the transmission provider 

evaluates whether service can be 

granted in every hour of the year that is 

modeled and, if not, it informs the 

customer that service cannot be 

provided out of existing transfer 

capability. Only if the transmission 

customer agrees to pay for facilities 

studies does the transmission provider 

evaluate redispatch options, including 

whether they are less expensive than the 

upgrade costs. The Commission 

therefore proposed to reform the 

existing pro forma OATT planning 

redispatch 67 obligation, or, in the 

alternative, to add a conditional firm 

service to the pro forma OATT. As 

proposed by the Commission, 

conditional firm would have been a 

long-term service allowing the 

transmission provider to give a lower 

curtailment priority than firm to the 

transmission customer during a prespecified number of hours. 

Comments 

74. Some commenters support the 

inclusion of both a modified planning 

redispatch obligation and a conditional 

firm service in the pro forma OATT, 

stating that both are required to remedy 

undue discrimination and provide for 

comparable transmission service. These 

commenters urge the Commission to 

require transmission providers to offer 

planning redispatch and conditional 

firm service and allow customers to 

choose the option that best suits their 

physical, commercial and economic 

circumstances. 

75. Others opine that conditional firm 

service may be simpler and less costly 

to implement. These commenters prefer 

the development of conditional firm 

service over the modifications to the 

planning redispatch service because of 

the complexities surrounding redispatch 

costs and protocols. For example, 

Entergy believes conditional firm 

service can provide benefits to 

transmission customers without unfairly 

socializing costs to native load and 

network customers of the transmission 

provider. 

76. On the other hand, many 

commenters argue that the Commission 

should not require either option because 

the services are unnecessary, 

operationally unworkable, and legally 

unjustified, or because they would harm 

reliability and the quality of existing 

network service and provide 

disincentives for transmission 

investment. Several commenters state 

that these services would make 

curtailments of existing firm service 

more likely and limit opportunities for 

use of secondary network service, 

thereby harming native load protections 

and reducing reliability, contrary to FPA 

sections 215 and 217 respectively. 

While it recognizes that conditional firm 

service has been successful in parts of 

the Western Interconnection, NRECA 

contends that a mandate would 

undermine responsible planning and 

expansion of the transmission grid by 

harnessing the transmission provider’s 

planning and dispatch functions to 

frame elaborate service conditions for 

conditional firm service. 

77. Several commenters argue that, if 

the services are required, the 

Commission should ensure that 

reliability is not adversely affected. 

Others urge the Commission to make the 

new services an interim option until 

transmission upgrades are in place to 

provide firm service. Some commenters 

believe planning redispatch and 

conditional firm customers should bear 

the actual costs of the services received, 

including costs associated with system 

operational changes needed to 

accommodate the services. A few 

commenters believe that the 

Commission should allow for regional 

differences in development of the new 

services. 

Commission Determination 

78. The Commission believes it is 

necessary to modify the manner in 

which transmission providers assess 

point-to-point service requests to 

eliminate the potential for undue 

discrimination in transmission service. 

We find that both techniques—planning 

redispatch and conditional firm 

service—are currently used under 

certain circumstances by transmission 

providers to serve native load and, 

therefore, that transmission customers 

should have comparable services in 

order to avoid undue discrimination, 

facilitate the provision of long-term 

transmission service and provide 

customers with greater flexibility in 

choosing resources to meet their needs. 

We expect that both options will help 

integrate new generation more quickly. 

This can be particularly beneficial to 

renewable generation resources, such as 

wind, that can be constructed more 

quickly than the transmission upgrades 

necessary to deliver their power on a 

firm basis over the long-run. 

G. EPAct 2005 Emphasized Certain 

Policies and Priorities for the 

Commission 

79. Finally, we note that the reforms 

adopted in this proceeding are 

consistent with the policies and 

priorities embodied in EPAct 2005, in 

which Congress emphasized many of 

the same principles reflected in this 

Final Rule. First, in EPAct 2005, 

Congress placed special emphasis on 

the development of transmission 

infrastructure. Congress required the 

Commission to adopt a rule establishing 

incentive-based rates for new 

transmission infrastructure investment. 

The stated purpose of new FPA section 

219 is to benefit ‘‘consumers by 

ensuring reliability and reducing the 

cost of delivered power by reducing 

transmission congestion.’’ 68 Among 

other steps, FPA section 219 requires 

the Commission to ‘‘(1) Promote reliable 

and economically efficient transmission 

and generation of electricity by 

promoting capital investment in the 

enlargement, improvement, 

maintenance, and operation of all 

facilities for the transmission of electric 

energy in interstate commerce, 

regardless of the ownership of the 

facilities; (2) provide a return on equity 

that attracts new investment in 

transmission facilities (including related 

transmission technologies); [and] (3) 

encourage deployment of transmission 

technologies and other measures to 

increase the capacity and efficiency of 

existing transmission facilities and 

improve the operation of the 

facilities.’’ 69 In addition, Congress 

directed the Commission to encourage 

the deployment of advanced 

transmission technologies.70 Congress 

also gave the Commission certain 

‘‘backstop’’ transmission siting 

authority, and authorized the creation of 

interstate compacts establishing 

transmission siting agencies.71 Finally, 

the Commission was directed to 

exercise its authority under EPAct 2005 

‘‘in a manner that facilitates the 

planning and expansion of transmission 

facilities to meet the reasonable needs of 

load-serving entities to satisfy the 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12279 

72EPAct 2005 sec. 1233(a) (to be codified at 

section 217(b)(4) of the FPA, 16 U.S.C. 824q). The 

Commission implemented FPA section 217(b)(4) in 

Long-Term Firm Transmission Rights in Organized 

Electricity Markets, Order No. 681, 71 FR 43564 

(Aug. 1, 2006), FERC Stats. & Regs. ¶ 31,226 (2006), 

order on reh’g, Order No. 681–A, 117 FERC ¶ 61,201 

(2006), reh’g pending. 

73EPAct 2005 sec. 1281 (to be codified at 16 

U.S.C. 824t). 

74EPAct 2005 sec. 1284(e)(1) (to be codified at 

section 316(A) of the FPA, 16 U.S.C. 825o–1). 

75Enforcement of Statutes, Orders, Rules and 

Regulations, Policy Statement on Enforcement, 113 

FERC ¶ 61,068 (2005) (Policy Statement on 

Enforcement). 

service obligations of the load-serving 

entities, and enables load-serving 

entities to secure firm transmission 

rights * * * on a long-term basis for 

long-term power supply arrangements 

made, or planned, to meet such 

needs.’’ 72 Although these provisions 

have been, or will be, addressed 

primarily in other proceedings, we 

conclude that the Final Rule is 

consistent with these provisions 

because it supports improvements in 

infrastructure by reforming the 

transmission planning process to ensure 

that it is open, transparent and 

nondiscriminatory. 

80. Second, Congress emphasized the 

need for greater transparency in 

electricity markets, including 

transmission service. EPAct 2005 added 

section 220 to the FPA, which requires 

the Commission to facilitate ‘‘price 

transparency in markets for the sale and 

transmission of electric energy in 

interstate commerce, having due regard 

for the public interest, the integrity of 

[that market], fair competition, and the 

protection of consumers.’’ 73 The 

Commission was authorized to 

‘‘prescribe such rules as the 

Commission determines necessary and 

appropriate to carry out the purposes 

of’’ FPA section 220. Those rules ‘‘shall 

provide for the dissemination, on a 

timely basis, of information about the 

availability and prices of wholesale 

electric energy and transmission service 

to the Commission, State commissions, 

buyers and sellers of wholesale electric 

energy, users of transmission services, 

and the public.’’ This Final Rule 

similarly will promote greater 

transparency in the provision of 

transmission service in many important 

areas, including ATC calculation and 

transmission planning. 

81. Finally, Congress emphasized 

compliance with the Commission’s 

regulations, increasing the civil and 

criminal penalties for violations of 

Commission-administered statutes and 

regulations.74 This new authority 

buttresses the Commission’s efforts to 

enforce public utility OATTs and the 

regulations requiring transmission 

information to be posted on OASIS. As 

we explained in the Policy Statement on 

Enforcement, however, this new 

authority carries with it the 

responsibility to ensure that 

enforcement is firm but fair and that our 

rules are as clear as practicable to 

facilitate compliance.75 We conclude 

that this Final Rule is fully consistent 

with these principles because it clarifies 

our rules, in many areas, which will 

facilitate compliance by transmission 

providers. 

IV. Summary, Scope and Applicability 

of the Final Rule 

82. This section provides a summary 

of the major components of the Final 

Rule, a description of the core elements 

of Order No. 888 that we retain, and a 

discussion of the applicability of the 

proposed rule to various entities. 

A. Summary of Reforms 

83. Consistency and transparency of 

ATC calculations. The Commission 

affirms the finding in the NOPR that the 

lack of a consistent, industry-wide 

methodology for calculating ATC, and 

the lack of adequate transparency in 

ATC calculations, increases the 

potential for undue discrimination and 

also makes undue discrimination more 

difficult to detect. The lack of consistent 

standards can facilitate undue 

discrimination by giving a transmission 

provider the discretion, and hence the 

ability and opportunity, to favor itself 

and its affiliates over third parties in 

how it calculates and allocates ATC. In 

this Final Rule, we give the industry 

specific guidance regarding the 

calculation of ATC and establish a firm 

deadline to develop certain 

requirements to make more consistent 

the ATC calculation process and the 

process of exchanging data between 

transmission providers about ATC. In 

addition, we amend pro forma OATT 

requirements as well as our OASIS 

regulations to increase the transparency 

in how ATC is calculated. 

84. Requirement for coordinated, 

open and transparent transmission 

planning. The Commission also affirms 

the finding in the NOPR that Order No. 

888 does not contain sufficient 

protections to guard against undue 

discrimination in transmission system 

planning. Without adequate 

coordination and open participation, 

market participants have minimal input 

or insight into whether a particular 

transmission plan treats all loads and 

generators comparably. To ensure that 

truly comparable transmission service is 

provided by all public utility 

transmission providers, including RTOs 

and ISOs, we amend the pro forma 

OATT to require coordinated, open, and 

transparent transmission planning on 

both a sub-regional and regional level. 

To implement this remedy, we adopt 

the eight planning principles proposed 

in the NOPR, as well as one additional 

principle, that each public utility 

transmission provider will be required 

to follow. We recognize that many 

regions have made significant progress 

in recent years in creating greater 

openness and transparency in 

transmission planning and believe our 

proposed reforms will build upon, 

strengthen, and improve this progress to 

reform transmission planning. 

85. Transmission Pricing Reforms. 

Consistent with the focus of Order No. 

888 on the non-rate terms and 

conditions of open access, the 

Commission does not initiate broad 

reform of transmission pricing policy 

through this Final Rule. However, we 

have identified several pricing rules that 

are part and parcel of OATT service that 

merit reform. 

• Energy and Generator Imbalance 

Charges. We find that energy and 

generator imbalance charges we have 

previously accepted are excessive, too 

varied, and otherwise unrelated to the 

cost of providing the service and, 

therefore, we reform energy and 

generator imbalance pricing. We adopt 

tiered pro forma OATT energy and 

generator imbalance provisions similar 

to those in use by Bonneville and 

exempt intermittent resources from the 

highest deviation band. In these new 

provisions, imbalance charges are based 

on incremental cost and escalate as the 

imbalance increases. Any deviations 

from these provisions must be 

consistent with or superior to the pro 

forma OATT as modified by this Final 

Rule and must meet the following 

criteria: the charges must (1) Be related 

to the cost of correcting the imbalance, 

(2) be tailored to encourage accurate 

scheduling behavior, such as by 

increasing the percentage of the adder as 

the deviations become larger, and (3) 

account for the special circumstances 

presented by intermittent generators, 

such as by waiving the higher ends of 

the deviation penalties. 

• Capacity Reassignment Pricing. We 

find that the existing cap on the 

reassignment of point-to-point service is 

no longer just and reasonable and, 

therefore, we eliminate the cap. We 

believe that removing the cap will 

eliminate an unnecessary impediment 

to the resale of capacity, which in turn 

should increase utilization of the grid 

and otherwise ensure that point-to-point 

service is just, reasonable, and not 

unduly discriminatory. 


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• Crediting of Customer-Owned 

Facilities. We retain most elements of 

our existing policy respecting the 

crediting of customer-owned facilities, 

including the requirement that such 

facilities meet the integration standard. 

However, we eliminate the requirement 

that new facilities can receive credits 

only if they are ‘‘jointly planned’’

because this requirement provides a 

disincentive to coordinated planning. 

Rather, we provide that such new 

facilities are eligible for credits if such 

facilities are integrated into the 

operations of the transmission 

provider’s facilities. Customer-owned 

facilities shall be presumed to be 

integrated if those facilities, if owned by 

the transmission provider, would be 

eligible for inclusion in the transmission 

provider’s annual transmission revenue 

requirement. 

86. Improvements to Point-to-Point 

Service. The Commission concludes that 

the existing methods for evaluating 

requests for long-term firm point-topoint service are no longer just, 

reasonable, and not unduly 

discriminatory. The existing pro forma 

OATT allows the transmission provider 

to deny a request for long-term point-topoint service if that service is not 

available in a single hour of the period 

studied. We find that this approach is 

not comparable because, when a 

transmission provider considers a new 

resource to serve native load, the 

transmission provider does not 

eliminate an otherwise economic option 

because the resource may not be 

deliverable in a few hours of the year. 

To remedy this problem, the 

Commission adopts a ‘‘conditional 

firm’’ component to long-term point-topoint service that addresses the 

situation where firm service can be 

provided for most, but not all, hours of 

the period requested. We also reform the 

existing requirements for the provision 

of redispatch service to ensure that they 

are of greater use to transmission 

customers and more consistent with 

reliability planning and operation of the 

system. 

87. Reform of rollover rights. The 

Commission concludes that section 2.2 

of the pro forma OATT, which grants an 

ongoing right to transmission customers 

to renew or ‘‘roll over’’ their contracts, 

should be reformed. The current 

rollover rights do not provide 

consistency between the rights of 

rollover customers and the resulting 

obligations of transmission providers to 

plan and upgrade the system to 

accommodate rollovers. The 

Commission therefore amends section 

2.2 to ensure greater consistency with 

transmission planning and construction 

timelines and modifies the minimum 

term of the rollover rights to five years, 

rather than the current minimum term 

of one year. The Commission also 

requires that a transmission customer 

eligible for rollover rights provide notice 

of whether or not it will exercise its 

right of first refusal to renew the 

contract no less than one year before the 

expiration date of the transmission 

service agreement, rather than within 

the current 60-day period. 

88. Increases in transparency to 

lessen the opportunities to discriminate 

and reduce transaction costs. In 

addition to the increased transparency 

we require regarding the calculation of 

ATC and transmission planning, we 

increase the transparency of 

transmission service provided under the 

pro forma OATT in several other 

respects. For example, we require 

transmission providers and their 

network customers to use the 

transmission providers’ OASIS to 

request designation of a new network 

resource and to terminate the 

designation of an existing network 

resource. In addition, we require 

transmission providers to modify their 

OASIS so that requests to designate and 

terminate a network resource can be 

queried, allowing all parties access to 

such information. We also require 

transmission providers to post a list of 

their current designated network 

resources and all network customers’

current designated network resources on 

their OASIS. Finally, we require 

transmission providers to post on 

OASIS all their business rules, practices 

and standards that relate to transmission 

services provided under the pro forma 

OATT. 

89. Strengthening enforcement of the 

pro forma OATT. The reforms adopted 

in this Final Rule provide greater clarity 

in the terms and conditions of the pro 

forma OATT, resolving ambiguities in 

the existing pro forma OATT that have 

made undue discrimination easier to 

accomplish and more difficult to detect. 

Our new civil penalty authority under 

EPAct 2005 gives us ample power to 

remedy tariff violations, but it also 

places upon us an increased 

responsibility to make the rules as clear 

as possible. We fulfill that responsibility 

in the Final Rule by providing greater 

clarity where appropriate to several 

critical OATT provisions. We also adopt 

a number of posting and reporting 

requirements that will provide the 

Commission and market participants 

with information about each 

transmission provider’s performance of 

pro forma OATT obligations. For 

example, we require transmission 

providers to post specific performance 

metrics related to their completion of 

studies required under the pro forma 

OATT. We note that the Commission 

will continue to audit compliance with 

the pro forma OATT, and toward that 

end require transmission information 

kept on OASIS to be retained for audit 

purposes for five years. Finally, we 

adopt a number of reforms to 

operational penalties assessed under the 

pro forma OATT, including so-called 

‘‘over-use’’ penalties and the treatment 

of operational penalty revenues 

collected from transmission providers 

and their affiliates. 

90. Miscellaneous OATT 

improvements. Finally, we implement a 

number of improvements to the terms 

and conditions of the pro forma OATT 

to incorporate the lessons learned over 

the past ten years. We briefly note these 

below: 

• Designation of network resources. 

We provide clarification regarding the 

types of agreements that may be 

designated as network resources, the 

process for verifying whether 

agreements meet the requirements in the 

pro forma OATT, and the requirement 

for transmission providers to designate 

and undesignate network resources. We 

also require customers to submit an 

attestation with each application to 

designate a new network resource. 

• Reservation priorities. We change 

the priority rules to give certain priority 

to pre-confirmed transmission service 

requests submitted in the same time 

period. We also add price as a tiebreaker in determining reservation 

queue priority when the transmission 

provider is willing to discount 

transmission service. 

• Clarifications related to network 

service. We provide clarification related 

to use of network service on an ‘‘as 

available basis’’ and to ‘‘redirects’’ of 

network service. 

B. Core Elements of Order No. 888 That 

Are Retained 

91. Although we are adopting many 

important reforms to Order No. 888 and 

the pro forma OATT in this Final Rule, 

we emphasize that many of the core 

elements of Order No. 888 are retained. 

As the Commission noted in the NOPR, 

many of these core elements enjoy broad 

support from many sectors of the 

industry. A variety of commenters—in 

response to the NOI issued earlier in 

this proceeding and again in response to 

the NOPR—have urged the Commission 

to focus on meaningful incremental 

reforms to the pro forma OATT, rather 

than on industry restructuring. We share 

the view that Order No. 888 can be 

strengthened without discarding its 

fundamental structure. We discuss 


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76Order No. 888 at 31,781. 77 Id. at 31,771 (setting forth the seven-factor test). 78 Id. at 31,781. 79 Id. 80See New York v. FERC, 535 U.S. at 28. 

81E.g., Ameren, APPA, North Carolina 

Commission Reply, PNM–TNMP, and Southern. 

82See New York v. FERC, 535 U.S. at 28. 

83Order No. 888 at 31,745. 

84 Id. at 31,694. 

85 Id.; see pro forma OATT section 2.2. 

86Order No. 888–A at 30,198. 

87 16 U.S.C. 217(f). 88E.g., Ameren, E.ON, Tacoma, Arkansas 

Commission, EPSA, Southern, and TAPS. 

89APPA argues that the proposed definition of 

native load customers in section 1.21 is not 

technically consistent with FPA section 217 

because FPA section 217 does not distinguish 

among the types of power supply arrangements that 

an LSE must have to enjoy the protection of FPA 

section 217. Nevertheless, APPA states that it 

would not be fruitful to reopen the entire OATT 

framework to address this technical (but very 

important) definitional difference. 

90E.g., Arkansas Municipal, Constellation, Duke, 

Salt River, and South Carolina E&G. 

91E.g., Constellation, EPSA, and South Carolina 

E&G. 

below the core elements that are being 

retained and the comments received on 

these points. 

1. Federal/State Jurisdiction 

92. In Order No. 888, the Commission 

stated that it has exclusive jurisdiction 

over the rates, terms, and conditions of 

unbundled retail transmission in 

interstate commerce.76 Though the 

Commission adopted a test for 

determining what constitute 

Commission-jurisdictional transmission 

facilities and what constitute Statejurisdictional local distribution facilities 

in situations involving unbundled 

wholesale wheeling and unbundled 

retail wheeling,77 the Commission 

stated that it generally would defer to 

determinations by State regulatory 

authorities concerning where to draw 

the jurisdictional line under that test.78

The Commission declined to assert 

jurisdiction over bundled retail 

transmission, reasoning that ‘‘when 

transmission is sold at retail as part and 

parcel of the delivered product called 

electric energy, the transaction is a sale 

of electric energy at retail.’’ 79 The U.S. 

Supreme Court affirmed the 

Commission’s decision to assert 

jurisdiction over unbundled but not 

bundled retail transmission, finding that 

the Commission made a statutorily 

permissible choice.80 In the NOPR, the 

Commission proposed to retain the 

jurisdictional divide established in 

Order No. 888. 

Comments 

93. Several commenters support the 

Commission’s proposal to retain the 

existing jurisdictional divide.81 Though 

APPA concludes that the most politic 

course at this juncture is to leave the 

current jurisdictional boundaries in 

place and develop cooperative 

mechanisms in each region to 

coordinate Federal policy 

implementation with the relevant State 

regulators, APPA notes that there is 

disagreement among its members about 

whether the current jurisdictional lines 

are properly drawn. APPA explains that 

a substantial number of its members 

believe that all interstate transmission 

services (both retail and wholesale) 

should be provided under one 

consistent set of tariff terms and 

conditions. Other APPA members, 

however, believe that the Commission 

made the proper jurisdictional call in 

Order No. 888. NARUC urges the 

Commission to clarify that its planning 

proposals will not reopen or attempt to 

change the jurisdictional split over 

transmission facilities delineated in 

Order No. 888. 

Commission Determination 

94. The Commission will retain the 

existing jurisdictional divide that was 

established in Order No. 888, which has 

been affirmed by the U.S. Supreme 

Court and accepted by the industry and 

State regulatory authorities.82 We also 

reiterate our recognition of the need for 

heightened cooperation between Federal 

and State regulators in areas where there 

are overlapping Federal and State policy 

concerns. As explained in greater detail 

in the planning section below, and in 

response to NARUC’s concern, the 

planning reforms adopted in the Final 

Rule contemplate coordinated and open 

transmission planning, but do not 

reopen or otherwise change the existing 

jurisdictional divide for transmission 

facilities. 

2. Native Load Protection 

95. In Order No. 888, the Commission 

did not require transmission providers 

to unbundle transmission service to 

their retail native load. The Commission 

also did not require that bundled retail 

service be taken under the terms of the 

pro forma OATT.83 Moreover, the 

Commission allowed a transmission 

provider to reserve, in its calculation of 

ATC, transmission capacity necessary to 

accommodate native load growth 

reasonably forecasted in its planning 

horizon.84 Order No. 888 also granted a 

rollover right to existing firm service 

customers,85 but allowed transmission 

providers to restrict that rollover right if 

the capacity was reasonably forecasted 

as needed to serve native load 

customers, as long as that restriction 

was set forth in the customer’s initial 

service contract.86

96. Congress, in section 1233 of EPAct 

2005, added section 217 to the FPA, 

entitled ‘‘Native Load Service 

Obligation,’’ which addresses 

transmission rights held by load-serving 

entities (LSEs). FPA section 217 allows 

LSEs to use their own and contractedfor transmission capacity to deliver 

energy as required to meet their service 

obligations, without being subject to 

charges of unlawful discrimination. The 

provision makes clear, however, that 

this requirement does not abrogate any 

contract or service agreement for firm 

transmission service or rights in effect 

as of the date of enactment of EPAct 

2005.87 In the NOPR, the Commission 

concluded that the protection of native 

load embodied in Order No. 888 is 

consistent with FPA section 217, and 

reaffirmed its commitment to the 

protection of native load. 

Comments 

97. Several commenters agree with 

the Commission’s preliminary 

conclusion that the protection of native 

load embodied in Order No. 888 is 

consistent with FPA section 217 and 

support the Commission’s continued 

commitment to the protection of native 

load.88 While APPA 89 and TAPS 

generally agree with the Commission 

that the overall OATT regime is 

consistent with section 217, they urge 

the Commission to maintain and 

reinforce the comparability requirement. 

APPA urges the Commission to broaden 

its preliminary conclusion in the NOPR 

and conclude instead that the protection 

of native load and the provision of fully 

comparable transmission service to 

other LSEs with long-term service 

obligations, as embodied in Order No. 

888, are consistent with FPA section 

217. TAPS also supports the 

Commission’s reading of FPA section 

217 as consistent with the Order No. 

888 pro forma OATT’s ‘‘native load’’

priority, recognizing that FPA section 

217 reinforces the OATT’s commitment 

to comparable treatment of all LSEs—

e.g., transmission providers and 

network customers. 

98. Other commenters dispute the 

Commission’s preliminary conclusion 

that the native load protection 

embodied in Order No. 888 is consistent 

with FPA section 217.90 Many 

commenters argue that FPA section 217 

protects all load, not just native load.91

Constellation states that the 

Commission must recognize that there 

are other market participants besides the 

transmission providers themselves that 

are LSEs under FPA section 217. Under 

the definition of LSEs in FPA section 


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12282 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

92 176 F.3d 1090, 1096 (8th Cir. 1999), cert. 

denied sub nom. Enron Power Marketing, Inc. v. 

Northern States Power Co., 528 U.S. 1182 (2000). 

217, EPSA argues that many entities 

other than traditional, verticallyintegrated utilities are in the business of 

serving load. The statute, EPSA asserts, 

applies to any native load service 

obligation, whether that obligation is 

served by a competitive supplier, an 

affiliate of the transmission provider, or 

by the transmission provider itself. Salt 

River contends that FPA section 217 is 

self-implementing, though it urges the 

Commission to act to remove 

impediments to the full exercise of 

rights granted to LSEs. 

99. Constellation argues that the 

Commission should require native load 

and OATT customers to take service 

under the same terms and conditions 

because experience has proven that 

discrimination has occurred as a result 

of having two different sets of rules 

applicable to transmission customers. 

EPSA urges the Commission to further 

clarify that the transmission provider 

has an affirmative obligation to serve 

native load in a non-discriminatory 

manner. According to EPSA, section 217 

supports the Commission’s paramount 

statutory mission of ensuring nondiscrimination and makes clear that a 

transmission provider, when utilizing 

transmission capacity or rights reserved 

to serve native load, must ‘‘put its 

blinders on’’ to ensure that the load’s 

needs are being met in the most 

economical way available, whether that 

decision means the deployment of its 

own affiliated generation, or the 

deployment of available non-utility 

alternatives. 

100. Arkansas Municipal asserts that 

FPA section 217 recognizes the need to 

give priority to LSEs in certain 

situations, such as when the 

transmission grid may be constrained 

and one group of customers may be 

denied service at the expense of other 

customers. Arkansas Municipal states 

that a priority list could be instituted in 

this reform proceeding that places LSEs 

at the top of the list in competing 

requests for transmission service when 

not all requests could be granted or 

honored by the transmission provider. 

101. New Mexico Attorney General 

argues that native load is fundamentally 

different than merchant load and 

therefore, in the planning process, the 

needs of merchants should not be 

treated comparably with the needs of 

New Mexico utilities’ native loads. New 

Mexico Attorney General asserts that 

New Mexico utilities have a statutory 

obligation to serve retail load while 

merchants are free to come and go with 

cycles inherent in wholesale markets. 

According to New Mexico Attorney 

General, the transmission requirements 

of the utilities’ native loads amount to 

an ongoing long-term firm contract, 

while the transmission needs of 

merchants are, by comparison, shortterm and speculative. 

102. Several commenters urge the 

Commission to revisit various aspects of 

the reforms proposed in the NOPR in 

order to enhance the protection of 

native load. For example, some 

commenters urge the Commission to 

modify the rollover proposal in the 

NOPR. Salt River argues that the 

Commission’s regulations must include 

a clear provision for a transmission 

owner anticipating, or unexpectedly 

facing, load growth to recapture 

capacity temporarily made available to 

the wholesale market. Arkansas 

Commission disagrees with the 

Commission’s proposal to require a 

transmission provider to compete for 

transmission capacity rather than 

reclaim it through its rights to reserve 

capacity for future load growth. The 

proposal is inequitable, Arkansas 

Commission argues, because native load 

customers have historically paid for 

most of the transmission providers’

assets and will continue to do so in the 

future. Because of this, Arkansas 

Commission asserts, native load 

customers should be given preference in 

the reservation of transmission capacity. 

In response to Arkansas Commission’s 

position, MDEA urges the Commission 

to make clear, consistent with the 

comparability principle adopted in 

Order No. 888 and reaffirmed in the 

NOPR, and with FPA section 217, that 

any reservation of rights or preference 

available to a transmission provider’s 

native load customers must be available 

to network customer loads as well. 

South Carolina E&G argues that the 

Commission’s interpretation of 

‘‘reasonably forecasted’’ capacity under 

section 2.2 of the pro forma OATT has 

been effectively impossible to meet and, 

therefore, the Commission should now 

provide clear standards for evaluation of 

native load protecting rollover 

restrictions. A clear standard, South 

Carolina E&G states, would have the 

Commission consider rollover 

restrictions in light of a utility’s 

transmission planning process. On 

reply, Progress Energy supports South 

Carolina E&G’s comments. Progress 

Energy urges the Commission to revisit 

the rollover rights policy to develop a 

policy by which an LSE may be assured 

of future transmission service for 

reasonably forecasted native load 

growth. 

103. South Carolina E&G also asks the 

Commission to revise section 13.6 of the 

pro forma OATT, regarding curtailment 

of firm point-to-point transmission 

service. South Carolina E&G urges the 

Commission to comply with the 

mandate of Northern States Power Co. v. 

FERC,92 which South Carolina E&G 

asserts held that the Commission had 

exceeded its authority in rejecting a 

vertically-integrated transmission 

provider’s proposal to modify section 

13.6 of the OATT to give a higher 

curtailment priority to native load. 

According to South Carolina E&G, the 

Commission has responded by applying 

the court’s decision narrowly, but FPA 

section 217 requires the Commission to 

change that position and recognize the 

primacy of service to native load in 

section 13.6 of the OATT. In its reply 

comments, Progress Energy supports the 

comments of South Carolina E&G and 

states that the Commission must 

affirmatively recognize the priority of 

service to LSEs in the application of the 

curtailment priorities in section 13.6 of 

the OATT. 

104. Duke argues that several of the 

Commission’s proposed reforms—such 

as hourly firm service, redispatch, and 

conditional firm service—actually 

reduce the protection afforded native/ 

network load. Salt River suggests that 

the Commission should modify its ATC 

proposal to bring the Commission’s 

native load priority policies in line with 

FPA section 217. Salt River asserts that, 

in calculating ATC, the transmission 

provider must be able to exercise 

reasonable professional judgment as to 

the amount of transmission that must be 

reserved to meet native load service 

obligations; the Commission should not 

get into the business of dictating 

forecasting methodology. Salt River 

proposes that a native load forecast that 

is used by an LSE as the basis for 

committing capital for generation 

expansion or procurement should be 

presumed to be valid for purposes of 

establishing available capacity. EPSA, 

however, argues that, unless and until 

the Commission mandates a hard and 

enforceable definition of ATC, 

transmission-owning utilities that also 

own affiliated generation will continue 

to hide behind the native load service 

obligation as an excuse for being unable 

to find ATC for any but self-serving 

purposes. 

105. EPSA also argues that the 

Commission must ensure that 

transmission owners’ planning 

accommodates all supply options. EPSA 

urges the Commission to clarify that 

transmission capacity reserved for 

native load is to be made available 

(including for study and other purposes) 

to competitive suppliers who wish to 


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93Proposals related to other reforms, such as 

curtailments and rollovers, are discussed in the 

sections below dealing with each of those issues. 

94See supra note 72. 95E.g., MISO/PJM States, TVA, and Southern. 

serve native load as allowed by State 

law. According to EPSA, all generation 

assets ultimately serve load and the pro 

forma OATT should be clarified to 

ensure that the transmission system is 

available on a non-discriminatory basis 

now and in the future to ensure that 

load is optimally served—regardless of 

which generation resources are serving 

that load. In its reply comments, EPSA 

also challenges the initial comments of 

New Mexico Attorney General, which 

EPSA argues incorrectly interpret FPA 

section 217 as drawing a distinction 

between the types of generation that 

serve load. EPSA argues that the statute 

protects the customer load that all 

suppliers would seek to serve regardless 

of the source. 

106. APPA agrees with the 

Commission’s response in the NOPR to 

Metropolitan Water District that the 

specific issues related to an RTO’s 

provision of long-term transmission 

rights are better left to the rulemaking in 

Docket Nos. RM06–8–000 and AD05–7–

000, and the proceedings in each RTO 

region to implement the Final Rule 

issued in those dockets on July 20, 2006. 

APPA notes, however, that the 

Commission has not proposed in this 

docket to exempt RTOs from the 

provisions of the NOPR. Rather, APPA 

notes, departures from the pro forma 

OATT, including departures in RTO 

OATTs, must be justified under the 

‘‘consistent with or superior to’’

standard. APPA argues that the 

Commission should apply this standard 

to long-term transmission rights, as well 

as to the other terms and conditions of 

OATT transmission service that RTOs 

provide. 

Commission Determination 

107. In Order No. 888, the 

Commission gave public utilities the 

right to reserve existing transmission 

capacity needed for native load growth 

reasonably forecasted within the 

utility’s current planning horizon. The 

Commission also allowed transmission 

providers to restrict rollover rights 

based on reasonably forecasted need at 

the time the contract is executed. We 

continue to believe these protections for 

native load are appropriate and do not 

eliminate them in this Final Rule, as 

suggested by some commenters. We also 

believe that the protection of native load 

embodied in Order No. 888, as 

enhanced by the reforms adopted in this 

Final Rule, is consistent with FPA 

section 217, which protects the 

transmission rights of entities with 

service obligations to end-users or a 

distribution utility, to the extent 

required to meet their service 

obligations. The additional reforms 

proposed by commenters are not 

necessary at this time to remedy undue 

discrimination. We conclude that the 

native load priority established in Order 

No. 888 continues to strike the 

appropriate balance between the 

transmission provider’s need to meet its 

native load obligations and the need of 

other entities to obtain service from the 

transmission provider to meet their own 

obligations. 

108. In response to comments 

regarding reforms needed to ATC 

calculation and transmission planning 

to bring the native load priority policies 

in line with FPA section 217, we believe 

that the Commission’s reforms in this 

Final Rule appropriately reflect the 

transmission provider’s obligation to 

serve native load. As discussed more 

fully in the ATC and planning sections 

below, the processes we adopt herein 

are open, transparent and nondiscriminatory and assume that the 

transmission provider is meeting its 

obligations, including its native load 

service obligation. We disagree with 

Duke’s assertion that the reforms 

proposed in the NOPR will result in a 

reduction of the protection afforded 

native or network load. Not only have 

we reaffirmed the fundamental 

protections for native load contained in 

Order No. 888, but we have modified, 

where appropriate, the pro forma OATT 

to ensure that a transmission provider’s 

obligations can be met consistent with 

maintaining the reliability to existing 

customers, including native load. For 

example, we are eliminating the current 

requirement to provide planning 

redispatch over long periods of time 

(e.g., 10–30 years) because it is 

unnecessary to remedy undue 

discrimination and can create problems 

in forecasting system conditions 

consistent with maintaining reliability 

to native load customers.93

109. With regard to APPA’s comments 

regarding long-term transmission rights 

in organized markets, we note that the 

Commission has issued its Final Rule in 

Docket Nos. RM06–8–000 and AD05–7–

000.94 As discussed more fully in the 

applicability section of this rulemaking, 

and in response to APPA’s comments, 

we reiterate that any departures from 

the pro forma OATT proposed by an 

ISO or an RTO must be ‘‘consistent with 

or superior to’’ the pro forma OATT in 

this Final Rule. 

3. The Types of Transmission Services 

Offered 

110. In Order No. 888, the 

Commission required all public utilities 

to offer, on a non-discriminatory, openaccess basis, firm network service and 

firm and non-firm point-to-point 

service. In the NOPR, the Commission 

proposed to retain these services and 

did not propose to require transmission 

providers to adopt a network contract 

demand service, either as a replacement 

for network or point-to-point service or 

as a third category of service under the 

OATT. 

Comments 

111. Several commenters support the 

Commission’s proposal to retain the 

current services in the pro forma OATT 

and to not adopt contract demand 

service.95 While APPA supports the 

Commission’s proposal, it states that the 

Commission should remain open to 

individual public utility transmission 

provider’s proposals to add ‘‘hybrid’’

service to the base network and pointto-point services. 

112. Other commenters, such as AMPOhio and Nevada Companies, argue that 

the Commission should require all 

transmission providers to offer network 

contract demand service. Nevada 

Companies argue that the Commission’s 

network designation process can 

substantially interfere with State 

jurisdiction over resource acquisition, 

especially for transmission providers 

that are required to purchase substantial 

amounts of power to serve their retail 

customers instead of relying primarily 

on their own generation. Nevada 

Companies reason that allowing 

transmission providers to move to a 

contract demand-based network service 

would remove them from the dilemma 

of being forced to make resource 

procurement decisions that are 

inconsistent with State requirements. 

On reply, MidAmerican, Newmont 

Mining, and Utah Municipals oppose 

the suggestion that the contract demand 

service should be made a mandatory 

service offering in the pro forma OATT. 

In its reply comments, Newmont Mining 

states that, if the Commission is 

inclined to provide some relief to allow 

Nevada Companies to comply with both 

the pro forma OATT and their Stateapproved resource plans, that relief 

should come only after an investigation 

of how similar problems are handled on 

other systems and should be a narrowly 

and carefully monitored exception to 

the resource designation requirements. 


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96Alberta Intervenors assert that the purchase of 

point-to-point service by dominant network 

customers results in an equal and offsetting 

reduction to the network customer’s network 

charges, resulting in a net cost of zero. They state 

that point-to-point service is a net cost to all 

competitors except the dominant network customer. 

Thus, they argue, a dominant network customer can 

buy point-to-point service for an extended period 

and use this service for a limited number of hours 

at little (or no) net cost compared to not purchasing 

point-to-point service for an extended period. In 

Alberta Intervenors’ view, this ‘‘free option’’

provides network customers with a competitive 

advantage when reserving point-to-point service 

because it enables the network customers to overconsume or buy excess point-to-point service than 

they would if the true net cost were reflected. 

Alberta Intervenors contend that such overconsumption reduces access to point-to-point 

service for other customers. 97Alberta Intervenors define ‘‘parking’’ as a 

network customer reserving point-to-point service 

using a network load point of delivery to purchase 

energy that it intends to sell but where no buyer has 

been identified at the time of the reservation. The 

energy notionally reduces network load. Once a 

buyer is found, the network customer completes the 

sale by delivering the energy from freed-up 

generation at a generation point of receipt to a 

buyer’s point of delivery. 

98Alberta Intervenors define ‘‘hubbing’’ as a 

practice very similar to ‘‘parking,’’ but involving 

multiple buyers and sellers. The network customer 

can reserve point-to-point transmission to purchase 

energy from multiple sellers and to sell energy to 

multiple buyers by creating a hub within its 

network load. Alberta Intervenors explain that this 

allows the network customer to organize purchases 

and sales by physically matching the requirements 

of multiple buyers and sellers. 

99Order No. 888 at 31,654. 

100See Duke Power, 113 FERC ¶ 61,288 (2005); 

MidAmerican Energy Co., 113 FERC ¶ 61,274 

(2005); see also Entergy Services, Inc., 110 FERC 

61,295 (2005), order on clarification, 111 FERC 

¶ 61,222 (2005), order conditionally approving 

filing, 115 FERC ¶ 61,095 (2006). 

113. Alberta Intervenors argue that 

undue discrimination is most likely to 

occur in situations where there is a 

single or dominant network customer 

and that customer either has a dual 

mandate for serving the network 

customers or that customer has a ‘‘free 

option’’ for procuring transmission.96

Alberta Intervenors recommend that the 

Commission implement standardized 

rules with respect to the ‘‘free option’’

concept while offering regional 

flexibility to ensure the objectives of 

open access and the absence of undue 

discrimination continue to be advanced. 

Alberta Intervenors also argue that, 

despite the Commission’s proposal to 

address undue discrimination against 

transmission customers in attempting to 

redirect to new receipt and delivery 

points, undue discrimination remains a 

concern since network customers retain 

a flexibility of receipt and delivery 

points that is not granted to third party 

point-to-point customers. This 

flexibility provided to the network 

customer allows the use of the system 

for activities known as ‘‘parking’’ 97 and 

‘‘hubbing.’’ 98 Alberta Intervenors urge 

the Commission to eliminate this unfair 

competitive advantage under the OATT 

by making a common service available 

to all participants rather than differing 

service for network customers, or 

alternatively, by restricting the use of 

point-to-point services by the network 

customer to exclude its use for 

‘‘parking’’ and ‘‘hubbing.’’

114. MidAmerican states that in the 

Western Interconnection, a utility’s 

loads are not necessarily located within 

a confined geographical boundary 

served by a single transmission owner. 

In these cases, MidAmerican argues, 

neither network nor point-to-point 

service under the current pro forma 

OATT is suitable to serve those loads. 

To remedy these shortcomings in 

standard OATT service, MidAmerican 

states that the Commission should 

require the incorporation of dynamic 

scheduling and long-term, seasonallyshaped, firm point-to-point as new 

service offerings under the pro forma 

OATT. 

Commission Determination 

115. The Commission will not alter 

the types of services that we required in 

Order No. 888. We continue to believe 

that network and point-to-point services 

are the appropriate base-line service 

offerings in the OATT, and we will not 

mandate that transmission providers 

adopt new service offerings such as 

network contract demand service. 

Although the Commission has accepted 

forms of network contract demand 

service proposed by individual 

transmission providers, and the service 

may provide benefits to certain 

customers, we do not believe the service 

is necessary to remedy undue 

discrimination. For example, the service 

would require a departure from full 

load-ratio pricing for network 

customers, which may not be warranted 

to the extent the transmission provider 

plans its system to serve all native load. 

However, while the Commission 

concludes that it will not require all 

transmission providers to offer this 

service, in response to the arguments 

raised by commenters such as AMPOhio and Nevada Companies, we 

reiterate that the Commission already 

has accepted forms of network contract 

demand service and will continue to 

entertain such proposals on a voluntary 

basis from transmission providers. 

116. The Commission also is not 

persuaded by Alberta Intervenors’ and 

MidAmerican’s arguments in support of 

further alternative services under the 

pro forma OATT. As with network 

contract demand service, transmission 

providers may propose such services if 

appropriate for their region. We do not 

believe mandating that such services be 

provided by all transmission providers 

is necessary at this time to prevent 

undue discrimination. 

4. Functional Unbundling 

117. In Order No. 888, the 

Commission chose to mandate 

functional, rather than corporate (in 

which a public utility’s transmission 

and generation assets would be placed 

in separate corporate entities), 

unbundling of transmission and 

generation services. The Commission 

explained that functional unbundling 

has three components: 

1. A public utility must take 

transmission services (including 

ancillary services) for all of its new 

wholesale sales and purchases of energy 

under the same tariff of general 

applicability as do others; 

2. A public utility must state separate 

rates for wholesale generation, 

transmission, and ancillary services; 

3. A public utility must rely on the 

same electronic information network 

that its transmission customers rely on 

to obtain information about its 

transmission system when buying or 

selling power.99

118. In the years following Order No. 

888, a number of public utilities 

nonetheless underwent corporate 

unbundling. Many of these entities did 

so as a result of State-mandated 

restructuring laws. Others did so for 

corporate or tax reasons. Some entities 

divested all of their generation assets to 

a non-affiliate, while others simply 

restructured internally to place the 

generation assets in a different corporate 

subsidiary than the transmission assets. 

There remain, however, a significant 

number of vertically-integrated public 

utilities that operate under the 

functional unbundling approach. 

119. In the NOPR, we proposed to 

preserve the functional unbundling 

approach adopted in Order No. 888, 

rather than impose a corporate or 

structural unbundling requirement. 

While the Commission expressed its 

continued support for voluntary efforts 

to adopt structural changes (such as 

transmission-only companies, RTOs, or 

other reforms), the Commission found 

that the more intrusive and costly 

corporate unbundling was not necessary 

at this time. The Commission also 

declined to mandate an independent 

transmission coordinator for all 

transmission providers. Though the 

Commission has previously found that 

such entities may be appropriate in 

certain circumstances and we support 

voluntary efforts to rely on them,100 the 


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101E.g., Santee Cooper, LPPC, TVA, Tacoma, 

Southern, MISO Transmission Owners, and E.ON. 

102Some commenters argue that adoption of the 

‘‘open dispatch’’ proposals raised by commenters 

such as Chandley-Hogan and PJM would constitute 

a departure from functional unbundling. We 

discuss the ‘‘open dispatch’’ and similar proposals 

in section V.C below. 

103The rules were first established in Order No. 

889. See Order No. 889 at 31,595. The Standards 

of Conduct rules were later replaced by a broader 

set of rules adopted in Order No. 2004, which were 

subsequently vacated in part by the United States 

Court of Appeals pending remand proceedings 

before the Commission. See Standards of Conduct 

for Transmission Providers, Order No. 2004, 68 FR 

69134 (Dec. 11, 2003), FERC Stats. & Regs. ¶ 31,155 

(2003), order on reh’g, Order No. 2004–A, 69 FR 

23562 (Apr. 29, 2004), FERC Stats. & Regs. ¶ 31,161 

(2004), order on reh’g, Order No. 2004–B, 69 FR 

48371 (Aug. 10, 2004), FERC Stats. & Regs. ¶ 31,166 

(2004), order on reh’g, Order No. 2004–C, 70 FR 284 

(Jan. 4, 2005), FERC Stats. & Regs. ¶ 31,172 (2005), 

order on reh’g, Order No. 2004–D, 110 FERC 

¶ 61,320 (2005), vacated, National Fuel, 468 F.3d 

831. The Commission has issued an interim rule 

promulgating temporary regulations consistent with 

the Court’s decision and initiated a further 

rulemaking to propose permanent regulations. See 

Standards of Conduct for Transmission Providers, 

Order No. 690, 72 FR 2427 (Jan. 19, 2007), FERC 

Stats. & Regs. ¶ 31,327 (2007); Standards of Conduct 

for Transmission Providers, Notice of Proposed 

Rulemaking, 72 FR 3958 (Jan. 29, 2007), FERC Stats. 

& Regs. ¶ 32,611 (2007) (Standards of Conduct 

NOPR). 

Commission concluded that there was 

not a sufficient basis for requiring them 

as a generic remedy for undue 

discrimination. 

Comments 

120. Commenters generally support 

the Commission’s proposal to retain 

functional unbundling.101 APPA also 

supports the Commission’s decision not 

to mandate an independent 

transmission coordinator for all public 

utility transmission providers. 

Similarly, Tacoma supports the 

Commission’s decision to continue to 

view participation in an RTO or ISO as 

voluntary actions. While PJM and EPSA 

would prefer a structural remedy, they 

generally support the Commission’s 

proposal to retain functional 

unbundling. However, EPSA states that 

given the Commission’s proposal to 

continue to rely on functional 

unbundling, it is critical, particularly in 

those areas without organized markets, 

that OATT rules regarding unbundled 

transmission service be clear, 

transparent, consistent, and rigorously 

enforced. APPA states that it will be 

vital to obtain the cooperation of State 

regulators in each region where the 

OATT reforms will be implemented to 

ensure that the current functional 

unbundling regime in fact is sufficient 

to do the job. 

121. E.ON and TVA express concern 

that the Commission may yet choose a 

structural remedy. E.ON urges the 

Commission to look at the full depth 

and breadth of its existing powers to 

monitor and fully redress any abuses in 

the allocation of transmission services 

before considering structural 

unbundling. Similarly, TVA notes that 

the Commission already has the option 

to impose a structural remedy on a caseby-case basis.102

Commission Determination 

122. The Commission will, as 

proposed in the NOPR, continue to 

require functional—rather than 

corporate or structural—unbundling. As 

explained in the NOPR, for public 

utilities that keep transmission and 

generation assets in the same corporate 

entity, the Commission has strict 

Standards of Conduct that require the 

separation of the utilities’ transmission 

system operations and wholesale 

marketing functions.103 These rules 

require that employees engaged in 

transmission functions operate 

separately from employees of energy 

affiliates and marketing affiliates. A 

number of information sharing 

restrictions also apply, which prohibit 

transmission providers from allowing 

employees of their energy and 

marketing affiliates to obtain access to 

transmission or customer information, 

except via OASIS. 

123. The Commission aggressively 

enforces the Standards of Conduct and, 

as referenced by APPA, cooperates with 

State regulators to ensure that the 

functional unbundling regime is 

sufficient to prevent undue 

discrimination. The Commission’s 

Office of Enforcement is well-suited to 

investigate potential violations of the 

Standards of Conduct and to propose 

remedies, including structural remedies 

if necessary, to ensure that the 

separation of functions and information 

restrictions are fully implemented. We 

believe that the increased clarity and 

transparency adopted in other parts of 

this Final Rule, when coupled with the 

Standards of Conduct rules and our 

rigorous enforcement program, will 

ensure that the functional unbundling 

requirement will serve its original 

purpose. 

C. Applicability of the Final Rule 

1. Non-ISO/RTO Public Utility 

Transmission Providers 

124. In the NOPR, the Commission 

proposed to apply the Final Rule to all 

public utility transmission providers, 

including those that are approved ISOs 

and RTOs. With respect to non-ISO/ 

RTO transmission providers, the 

Commission proposed to require all 

such transmission providers to submit 

FPA section 206 compliance filings, 

within 60 days after the publication of 

the Final Rule in the Federal Register, 

that contain the non-rate terms and 

conditions set forth in the Final Rule. 

The Commission also acknowledged 

that certain non-rate terms and 

conditions, such as Attachment C 

(relating to the transmission provider’s 

ATC calculation methodology) and 

Attachment K (relating to the 

transmission provider’s transmission 

planning process), may require more 

than 60 days to prepare and sought 

comment on an appropriate time period 

in which to require the submission of 

these attachments. 

125. Following their FPA section 206 

compliance filings, the Commission 

proposed that transmission providers 

could submit filings under FPA section 

205 proposing rates for the services 

provided for in the tariff, as well as nonrate terms and conditions that differ 

from those set forth in the Final Rule if 

those provisions are ‘‘consistent with or 

superior to’’ the pro forma OATT. 

Comments 

126. Several commenters ask the 

Commission to clarify and/or revise the 

proposal for dealing with previouslyapproved provisions that depart from 

the existing (Order No. 888) pro forma 

OATT. APPA contends that after this 

multi-phase rulemaking (NOI/NOPR/ 

Final Rule) to revise the OATT, the 

Commission should hold those public 

utility transmission providers that 

propose non-rate terms and conditions 

differing from the new pro forma OATT 

to a high standard of proof under the 

‘‘consistent with or superior to’’

standard. According to APPA, any nonrate term and condition that differs from 

the revised pro forma OATT should be 

‘‘additive’’ in nature (for example, a new 

service offering, such as network 

contract demand service) or should 

propose substantive improvements in 

transmission service to customers. 

APPA argues that a public utility 

transmission provider should not be 

able to make an FPA section 206 

compliance filing to implement the pro 

forma OATT and then ‘‘water down’’ its 

new OATT through an FPA section 205 

filing that degrades its transmission 

service offerings or diminishes the 

quality of that service. 

127. In its reply comments, APPA 

recommends that the Commission 

require non-ISO/RTO transmission 

providers to file the new pro forma 

OATT set out in the Final Rule and add 

in redline—either in that filing, or a 

companion one—all previously 

approved transmission provider-specific 


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104 Duke and EEI propose that a utility would 

redline its compliance filing OATT against the 

revised pro forma OATT so that the Commission 

can readily identify the ‘‘already-approved’’

differences. 

105The Commission clarifies that existing waivers 

of the obligation to file an OATT or otherwise offer 

open access transmission service in accordance 

with Order No. 888 shall remain in place. The 

reforms to the pro forma OATT adopted in this 

Final Rule therefore do not apply to transmission 

providers with such waivers, although we expect 

those transmission providers to participate in the 

regional planning processes in place in their 

regions, as discussed in more detail in section V.B. 

Whether an existing waiver of OATT requirements 

should be revoked will be considered on a case-bycase basis in light of the circumstances surrounding 

the particular transmission provider. 

106As explained below, the Commission is not 

requiring transmission providers to submit in their 

compliance filing tariff sheets associated with 

provisions of the pro forma OATT that have not 

been modified in this proceeding. To the extent, 

however, a transmission provider desires to refile 

its entire OATT in order to simplify pagination or 

other tariff designation issues associated with 

provisions. APPA states that 

transmission providers should then 

explain whether they propose to include 

these provisions in their revised OATTs, 

why they propose to retain or delete 

these provisions, and whether they 

believe these provisions are ‘‘affected by 

the revisions adopted in the Final 

Rule.’’

128. In contrast, Duke and EEI ask the 

Commission to clarify that transmission 

providers with previously-approved 

departures from the OATT that are not 

related to the reforms adopted in this 

Final Rule will not be required to 

rejustify these provisions in their FPA 

section 206 compliance filings. They 

also ask that transmission providers not 

be required first to adopt all of the 

provisions of the revised pro forma 

OATT and then make an FPA section 

205 filing to refile a departure 

previously approved by the 

Commission. They recommend that 

existing, approved departures from the 

pro forma OATT that are not affected in 

a substantive way by the changes to the 

pro forma OATT should be included in 

the initial FPA section 206 filing.104 On 

reply, Indianapolis Power agrees with 

Duke and EEI and urges the Commission 

to consider the unwieldy and cost 

prohibitive nature of a process that 

would require transmission providers to 

demonstrate that previously-accepted 

elements of their OATTs are acceptable. 

129. Duke and EEI, in their reply 

comments, argue that APPA’s approach 

would be inefficient and would cause a 

substantial disruption to transmission 

service because both transmission 

providers and transmission customers 

would be required to abandon tariff 

provisions that the Commission has 

previously found to be consistent with 

or superior to the pro forma OATT and 

that are regularly being used. For 

example, Duke notes, Duke Carolina has 

an Attachment K that covers the 

Independent Entity that will oversee the 

provision of transmission service by 

Duke. Duke asserts that a literal 

interpretation of the NOPR proposal 

would mean that it would have to delete 

this attachment and replace its entire 

OATT with the revised pro forma OATT 

and then refile its entire Independent 

Entity proposal with its FPA section 205 

filing. Similarly, Entergy states that it 

currently has a pro forma Generator 

Imbalance Agreement in place that was 

agreed to by the IPPs on its system and 

accepted by the Commission. Entergy 

urges the Commission to permit 

transmission providers to propose their 

own imbalance pricing methodology as 

long as the proposed generator 

imbalance charges are consistent with or 

superior to the generator imbalance 

provisions ultimately adopted in the 

OATT. 

130. On reply, NRECA opposes EEI’s 

compliance proposal. NRECA states that 

the Commission should retain the twophased compliance procedure proposed 

in the NOPR because it strikes a fair 

balance by providing transmission 

providers the opportunity to suggest 

changes to their pro forma OATTs 

under FPA section 205, while allowing 

transmission customers and others the 

opportunity to argue that the deviations 

from the new pro forma OATT are 

neither consistent with nor superior to 

the pro forma OATT. 

131. NRECA acknowledges that there 

will be a burden on the transmission 

provider to prepare a compliance filing; 

however, it urges the Commission to 

retain its proposal and require 

transmission providers to identify those 

terms and conditions that differ from 

the pro forma OATT. NRECA agrees 

that, if a term or condition unrelated to 

any modification of the pro forma 

OATT in the instant rulemaking has 

already been found to be consistent with 

or superior to the existing Order No. 888 

pro forma OATT, it likely continues to 

be consistent with or superior to the 

revised pro forma OATT term or 

condition. NRECA argues, however, that 

a public utility transmission provider 

should still be required in a compliance 

filing to identify these deviations from 

the revised pro forma OATT and, 

ultimately, to justify them in the event 

that they are fairly contested. Otherwise, 

NRECA contends, the Commission and 

industry lose the consistency and 

related advantages the pro forma OATT 

seeks to provide. 

132. Several commenters addressed 

the deadlines proposed in the NOPR. 

APPA suggests that the Commission set 

a 60 or 90-day deadline for those 

provisions the transmission provider 

can complete itself and a 120 or 180-day 

deadline for those provisions and 

attachments that will require the 

transmission provider to incorporate 

regional practices and protocols, such as 

Attachments C and K. Tacoma proposes 

180 days for transmission providers to 

submit Attachments C and K. PGP 

recommends that transmission 

providers be given one year to file 

Attachment K. 

133. EEI and National Grid urge the 

Commission to align the compliance 

filing deadlines for ISOs and RTOs and 

their transmission-owning members in 

order to eliminate any potential 

confusion and to enhance coordination 

within the ISOs and RTOs. To the extent 

that public utility transmission owners 

whose transmission facilities are under 

the control of RTOs and ISOs have filing 

rights under the RTO or ISO tariffs, EEI 

asks that such public utility 

transmission owners be required to 

submit any necessary tariff filings 

within 90 days after the effective date of 

the Final Rule, rather than the currentlyproposed 60 days. National Grid 

suggests that the Commission establish 

a single deadline for ISOs/RTOs and 

their transmission-owning members, set 

at six months from the date of 

publication of the Final Rule. 

134. TDU Systems recommend that 

the Commission adopt a staggered filing 

approach for the compliance filings (i.e., 

have transmission providers come in at 

different times based on criteria chosen 

by the Commission, such as 

alphabetically or by size). TDU Systems 

argue that this would ensure that 

transmission customers are not forced to 

review all of their transmission 

providers’ filings at the same time. 

Commission Determination 

135. The Commission adopts the twotiered implementation process proposed 

in the NOPR, with certain clarifications 

and modifications, as discussed below. 

As the Commission proposed in the 

NOPR, all transmission providers that 

have not been approved as ISOs or 

RTOs, and whose transmission facilities 

are not under the control of an ISO or 

RTO, are required to submit FPA section 

206 compliance filings that contain the 

revised non-rate terms and conditions 

set forth in the Final Rule, within 60 

days after the publication of the Final 

Rule in the Federal Register.105

However, this filing only need to 

contain the revised provisions adopted 

in the Final Rule, rather than the 

transmission provider’s entire pro forma 

OATT.106 After the submission of their 


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implementing the modifications required under the 

Final Rule, it may do so. We note that such a filing 

is a compliance filing and, therefore, the only 

deviations in this filing should be the revised 

provisions in this Final Rule. If a transmission 

provider wishes to propose different terms and 

conditions, it must make a separate FPA section 205 

filing. 

107Transmission providers must provide citations 

to the Commission orders where the variation was 

accepted by the Commission as consistent with or 

superior to the pro forma OATT. 

108For further information related to the Final 

Rule, such as electronic versions of the pro forma 

OATT showing tariff changes adopted in the Final 

Rule in redline/strikeout format, and further 

information regarding docketing of compliance 

filings and specific filing instructions, please visit 

our Web site at the following location http:// 

www.ferc.gov/industries/electric/indus-act/oattreform.asp. 

FPA section 206 compliance filings, 

these transmission providers may 

submit FPA section 205 filings 

proposing rates for the services 

provided for in the tariff, as well as nonrate terms and conditions that differ 

from those set forth in the Final Rule if 

those provisions are ‘‘consistent with or 

superior to’’ the pro forma OATT. 

136. The Commission recognizes that, 

since the issuance of Order No. 888, 

some non-ISO/RTO transmission 

providers have received approval from 

the Commission to adopt variations 

from the non-rate terms and conditions 

of the pro forma OATT that are 

consistent with or superior to the Order 

No. 888 pro forma OATT. Under the 

compliance procedure adopted above, 

those variations that are not affected in 

a substantive manner by the reforms to 

the pro forma OATT adopted in this 

Final Rule may remain in place. We 

disagree with the implementation 

procedures proposed by APPA, which 

would require non-ISO/RTO 

transmission providers with provisions 

in their OATTs that depart from the pro 

forma OATT, but which are not 

substantively affected by the reforms in 

this NOPR, to make a filing that 

explains whether and why they would 

retain or delete these provisions. We see 

no need to require non-ISO/RTO 

transmission providers to ‘‘rejustify’’

such provisions if they are not 

substantively affected by the reforms in 

this Final Rule, given that the 

Commission has already found these 

provisions to be consistent with or 

superior to terms and conditions set 

forth in the pro forma OATT that 

remain unchanged, and the Commission 

has not otherwise found these 

provisions to be unjust and 

unreasonable. 

137. In other circumstances, however, 

non-ISO/RTO transmission providers 

may have provisions in their existing 

OATTs that the Commission deemed to 

be consistent with or superior to terms 

and conditions of the Order No. 888 pro 

forma OATT that are being modified by 

the Final Rule. Such transmission 

providers must demonstrate that these 

previously-approved variations 

continue to be consistent with or 

superior to the pro forma OATT as 

modified by the Final Rule. We 

continue to believe that use of the 

‘‘consistent with or superior to’’

standard is appropriate when reviewing 

variations from the pro forma OATT 

and reject APPA’s proposal to adopt a 

higher burden of proof. 

138. The two-tiered compliance 

process adopted above will allow 

transmission providers with previouslyapproved variations an opportunity to 

show that their existing deviations 

continue to be consistent with or 

superior to the pro forma OATT as 

modified in the Final Rule. However, 

the Commission recognizes that it may 

cause disruption for some transmission 

providers that wish to continue to rely 

on previously-approved variations 

during the compliance process. The 

Commission therefore offers an optional 

implementation process for non-ISO/ 

RTO transmission providers seeking 

approval of previously-approved 

variations. 

139. Transmission providers that have 

not been approved as ISOs or RTOs and 

whose transmission facilities are not 

under the control of an ISO or RTO may 

submit an FPA section 205 filing, within 

30 days after the publication of the Final 

Rule in the Federal Register, seeking a 

determination that a previouslyapproved variation from the Order No. 

888 pro forma OATT that has been 

substantively affected by the reforms 

adopted in this Final Rule continues to 

be consistent with or superior to the 

revised pro forma OATT adopted 

here.107 Each applicant should request 

that the proposed tariff provisions be 

made effective as of the date of the 

transmission provider’s section 206 

compliance filing, to be submitted 

within 60 days after the publication of 

the Final Rule in the Federal Register 

(as provided above). As a condition of 

that request, however, the transmission 

provider should state that the 

Commission has 90 days following the 

date of submission of the filing to act 

under section 205. In other words, the 

Commission is offering this optional 

implementation process to applicants 

that allow the Commission 90 days to 

act on the filing. This procedure will 

streamline the compliance process by 

allowing existing variations from terms 

and conditions of the pro forma OATT 

that have been modified by the Final 

Rule to remain in effect until further 

Commission action, while also 

providing the Commission with 

adequate time to act on the filings. The 

subsequent section 206 compliance 

filing would then contain tariff sheets 

necessary to implement the remaining 

modifications required under the Final 

Rule, i.e., modifications related to tariff 

provisions that did not implicate 

previously-approved variations. 

140. As the Commission 

acknowledged in the NOPR, certain 

non-rate terms and conditions, such as 

Attachment C (relating to the 

transmission provider’s ATC calculation 

methodology) and Attachment K 

(relating to the transmission provider’s 

transmission planning process) may 

require more than 60 days to prepare. 

Accordingly, we will require non-ISO/ 

RTO transmission providers to file their 

Attachment C within 180 days after the 

publication of the Final Rule in the 

Federal Register and their -Attachment 

K (or the transmission providers’

equivalent thereof) within 210 days after 

the publication of the Final Rule in the 

Federal Register. A summary of the 

more significant filing requirements 

established in this Final Rule is 

provided in Appendix A.108

141. Other reforms adopted in the 

Final Rule will involve coordination 

with the North American Energy 

Standards Board (NAESB) to establish 

OASIS functionality or uniform 

business practices. The Commission 

requests that NAESB file a status report 

within 90 days of publication of the 

Final Rule in the Federal Register that 

contains a work plan for development of 

such OASIS functionality and business 

practices. This work plan should 

indicate, for each reform, what actions 

are necessary and an estimate of the 

timeframe for completing those actions. 

Pending resolution of these issues with 

NAESB, the Commission requires that 

each transmission provider develop its 

own OASIS functionality or business 

practice necessary to implement each 

such reform within 90 days of 

publication of the Final Rule in the 

Federal Register, unless a different 

compliance requirement is otherwise 

specified in this Final Rule. Upon 

review of this work plan, the 

Commission will issue an order 

establishing further compliance 

deadlines as necessary. 

142. We are not persuaded to adopt a 

staggered compliance filing approach in 

this proceeding as TDU Systems 

suggest. However, we will align the 

compliance filing deadlines for ISOs 

and RTOs and their transmissionVerDate Aug<31>2005 18:17 Mar 14, 2007 Jkt 211001 PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 E:\FR\FM\15MRR2.SGM 15MRR2

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109See also CMUA Reply. 

owning members in order to eliminate 

any potential confusion and to enhance 

coordination within the ISOs and RTOs. 

Thus, we will require public utility 

transmission owners whose 

transmission facilities are under the 

control of RTOs and ISOs to make any 

necessary tariff filings required to 

comply with the Final Rule within 210 

days after the publication of the Final 

Rule in the Federal Register. 

2. ISO and RTO Public Utility 

Transmission Providers and 

Transmission Owner Members of ISOs 

and RTOs 

143. With respect to an ISO or RTO 

public utility transmission provider, the 

Commission recognized in the NOPR 

that such an entity may already have 

tariff terms and conditions that are 

superior to the pro forma OATT. The 

Commission also noted that the purpose 

of this rulemaking is not to redesign 

approved, fully-functioning RTO or ISO 

markets. Thus, the Commission 

proposed to require ISO and RTO 

transmission providers to submit FPA 

section 206 compliance filings, within 

90 days after the publication of the Final 

Rule in the Federal Register, that 

contain the non-rate terms and 

conditions set forth in the Final Rule or 

that demonstrate that their existing tariff 

provisions are consistent with or 

superior to the revised provisions to the 

pro forma OATT. The Commission also 

proposed to allow ISO and RTO 

transmission providers, after making 

their FPA section 206 compliance 

filings, to submit filings under FPA 

section 205 proposing rates for the 

services provided for in their tariffs, as 

well as non-rate terms and conditions 

that differ from their existing tariffs and 

those set forth in the Final Rule if those 

provisions are consistent with or 

superior to the pro forma OATT. The 

Commission did not address the specific 

obligations of transmission owning 

members of ISOs and RTOs. 

Comments 

144. Several commenters support 

applying the revised pro forma OATT to 

ISOs and RTOs and requiring ISOs and 

RTOs to justify any variations 

therefrom. MidAmerican argues that 

universal application of the revised pro 

forma OATT is important because not 

every ISO or RTO transmission provider 

has existing tariff terms and conditions 

that are consistent with or superior to 

the OATT. Old Dominion also supports 

the Commission’s compliance proposals 

for ISOs and RTOs. NRECA similarly 

states that RTOs, ISOs and ITCs should 

not be automatically exempt from any 

aspect of the rules governing open 

access transmission service, including 

the planning requirements. APPA 

asserts that in their filings, RTOs should 

be required to show how their 

transmission service packages, 

including features such as long term 

transmission rights, ancillary services, 

and treatment of losses, are consistent 

with or superior to the newly revised 

pro forma OATT. Moreover, APPA 

argues, the Commission should not 

allow RTOs to use their avowed 

independence as a justification for 

transmission services that in fact do not 

meet the consistent with or superior to 

standard.109

145. On the other hand, numerous 

commenters argue that the proposed 

compliance process is burdensome and 

could require ISOs and RTOs to have to 

relitigate already-approved OATT 

provisions. The ISOs and RTOs 

generally argue that, given the nature of 

the services they offer, many of the 

proposed revisions do not apply to their 

OATTs. Many commenters urge the 

Commission to adopt a more limited 

compliance filing process. Some 

commenters, for example, argue that the 

Commission should only require ISOs 

and RTOs to submit compliance filings 

that are limited to the specific pro forma 

tariff revisions set forth in the Final 

Rule. Duke argues that ISOs and RTOs 

should only be required to make a single 

filing that revises their OATTs in a 

manner that takes into account the 

nature of the OATT service provided by 

that ISO or RTO and whether a reform 

adopted in the Final Rule is relevant to 

the ISO’s or RTO’s OATT. EEI urges the 

Commission to require ISOs and RTOs 

to adopt only those OATT reforms that 

are necessary to improve the quality of 

transmission service that is provided by 

an ISO or RTO. EEI adds that those who 

protest an ISO’s or RTO’s assertion that 

an existing provision is consistent with 

or superior to the revised pro forma 

OATT should have the burden to 

demonstrate otherwise. The ISOs and 

RTOs similarly argue that, absent a 

specific demonstration that an ISO’s or 

RTO’s OATT provisions are unjust and 

unreasonable, the compliance filing 

requirements should not apply to ISOs 

and RTOs. 

146. EEI urges the Commission to 

clarify that the 90-day filing should 

include the following materials: 

Revisions of tariff provisions that 

conform to the revisions in the pro 

forma OATT that are appropriate, given 

the ISO or RTO’s market structure; 

statements supporting the provisions of 

the tariff that the ISO or RTO believes 

are consistent with or superior to the 

revised pro forma OATT; and 

justifications that support excluding 

revisions of the provisions that the ISO 

or RTO believes are not consistent with 

or superior to the revised pro forma 

OATT. EEI also interprets the NOPR 

proposal to mean that an ISO or RTO 

immediately may make a separate filing 

proposing further modifications, 

including revisions to the newlyeffective provisions of the pro forma 

OATT, that are consistent with or 

superior to the just-filed modifications. 

147. SPP urges the Commission to 

affirm that ISOs and RTOs will not be 

required to rejustify their previouslyapproved non-pro forma tariff 

provisions, but rather only the new or 

revised tariff provisions expressly 

prescribed in the Final Rule. In its reply 

comments, SPP notes that the terms and 

conditions of its OATT are interrelated 

and work together to achieve a system 

of administration that fosters open and 

transparent transmission service and 

function as an integrated whole. 

Therefore, SPP asserts, the modification 

of one provision of its OATT will 

impact several other provisions and the 

process of rejustifying one aspect of the 

tariff likewise will implicate other terms 

and conditions. 

148. Indianapolis Power argues that 

tariff changes resulting from this 

rulemaking should be included only 

with the support of the ISO and RTO 

members who bear the costs and are in 

the best position to judge the benefits. 

149. On reply, ISO/RTO Council 

generally argues that there is no factual 

or legal support for the ISO/RTO 

compliance procedures advocated by 

commenters such as APPA. ISO/RTO 

Council states that the OATTs of ISOs 

and RTOs were developed through 

extensive stakeholder procedures and 

subject to the Commission’s filing, 

notice, comment, and approval 

processes under FPA section 205. ISO/ 

RTO Council asserts that to adopt the 

post-hoc, open-ended review advocated 

by these parties would give disgruntled 

participants a ‘‘second bite’’ at legally 

effective OATT terms and would 

undermine the very stakeholder and 

regulatory processes by which ISOs and 

RTOs were established. MISO in 

particular argues that APPA’s proposal 

ignores that ISO and RTO tariffs have 

already been determined to be just and 

reasonable and consistent with or 

superior to the Order No. 888 pro forma 

OATT, is profoundly inconsistent with 

the Commission’s policy of encouraging 

RTOs as an option to ensure nondiscriminatory open access transmission 

service, and is impracticable unless the 

intent is to grind RTO markets to a halt. 

MISO states that each RTO tariff has 


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dozens, or perhaps hundreds, of 

Commission-approved deviations and, 

in its view, reopening these issues 

would not be in the public interest and 

would consume enormous resources of 

both the RTOs and the Commission. 

150. Southern, in its reply comments, 

argues that ISOs and RTOs are 

essentially requesting to be exempted 

from the requirements of this 

proceeding. Southern states that all 

transmission service revisions/reforms 

adopted in this proceeding should apply 

uniformly to all transmission providers, 

including ISOs and RTOs. Southern 

contends that ISOs and RTOs are 

increasingly subject to complaints 

alleging discriminatory treatment and 

asserts that the highly partisan attacks 

made by several RTOs against verticallyintegrated utilities further calls into 

question whether ISOs and RTOs are 

not susceptible to taking discriminatory 

actions. In addition, Southern argues, 

such exemptions would likely result in 

seams issues. 

151. Some commenters state that the 

Commission should identify the specific 

reforms it will apply to RTOs and ISOs 

and provide more general guidance as to 

how it intends to apply the consistent 

with or superior to standard to ISO/RTO 

tariff provisions. National Grid asserts 

that the Commission properly identified 

these provisions in the NOPR when the 

Commission concluded that there may 

be elements of the proposed reforms 

that are superior to what currently exist 

in some RTOs or ISOs, e.g., 

transparency, data exchange, or 

planning. MISO/PJM States identify six 

areas as potentially applicable to RTOs: 

Hourly firm transmission service; 

obligation to expand capacity; joint 

ownership; reservation priority; 

ancillary services; and pro forma OATT 

definitions. MISO/PJM States also 

identify eleven areas as not applicable 

to RTOs: Undue discrimination 

generally; transmission pricing; 

remedies, penalties and enforcement; 

changes in receipt and delivery points 

(redirects); rollover rights; rules, 

standards and practices governing the 

provision of transmission service; joint 

transmission planning; tariff compliance 

review; hoarding of transmission 

capacity; curtailments; and ancillary 

services. APPA, in its reply comments, 

opposes granting a blanket exemption 

for ISOs and RTOs from any portion of 

the compliance filing requirement. 

152. CAISO urges the Commission to 

clarify how it should provide for 

changes in the Final Rule to 

transmission services that it does not 

provide or which are clearly 

incompatible with the transmission 

service model it employs. In their reply 

comments, CMUA and APPA oppose 

this request for clarification. CMUA 

argues that CAISO’s failure to provide 

any long-term transmission service 

renders its transmission service 

markedly inferior to the firm 

transmission service under the pro 

forma OATT. CMUA maintains that, 

instead of affirmatively embracing its 

obligation to show that its transmission 

service offering, once supplemented 

with long-term transmission rights that 

fully comply with all seven guidelines 

set out in Order No. 681, will meet the 

‘‘consistent with or superior to’’

standard of Order No. 888, CAISO 

instead asks to be exempted from any 

such requirement. 

153. Xcel and Indicated New York 

Transmission Owners assert that the 

Commission should allow regional 

variations to the extent that ISOs/RTOs 

can demonstrate that their OATT 

provisions meet the objectives of the 

Final Rule. Xcel argues that the 

consistent with or superior to standard 

may be too narrow because some 

changes to the OATT made by ISOs/ 

RTOs are not as much ‘‘superior’’ or 

‘‘consistent with,’’ as they are simply 

necessary because the tariff is regional. 

Indicated New York Transmission 

Owners argue that the Commission 

should not impose a consistent with or 

superior to standard generally reserved 

for transmission providers that are not 

members of an ISO/RTO. Indicated New 

York Transmission Owners assert that, 

to the extent that certain improvements 

could or should be made to the ISO/ 

RTO OATTs, the Final Rule should 

permit the necessary flexibility for each 

ISO/RTO to propose and adopt such 

changes through their stakeholder 

governance processes, in order to 

address the unique market features and 

circumstances of each region. 

154. PJM urges the Commission to 

include an ‘‘independent entity 

variation’’ standard similar to that used 

in Order No. 2003, which permitted an 

RTO to adopt interconnection 

procedures that are responsive to 

specific regional needs. NRECA 

responds that the Commission should 

not entertain PJM’s request. While PJM’s 

requested standard may have made 

sense in the context of generator 

interconnections, NRECA contends that 

it is inapposite to reform of the OATT. 

NRECA states that ISOs and RTOs 

should not be allowed to keep on file 

tariff provisions that possess the 

potential to allow for undue 

discrimination, even if the entity 

publishing the tariff is ostensibly 

independent of market participants and 

even if the proposed reforms do not 

directly improve the ‘‘quality of’’

transmission service, since the purpose 

of this rulemaking is to prevent undue 

discrimination in the provision of 

transmission service. 

155. To whatever extent the 

Commission elects to exempt RTOs and 

ISOs from certain aspects of the pro 

forma OATT, E.ON asserts that the same 

consideration should be given to 

utilities that have entered into 

arrangements with alternative, 

Commission-approved, independent 

transmission organizations. In their 

reply comments, TDU Systems oppose 

this proposal arguing that these 

alternative constructs may not meet the 

independence criteria of Order Nos. 888 

and 2000. 

156. Several commenters urge the 

Commission to extend the proposed 90- 

day deadline for ISOs and RTOs to 

submit their compliance filings. EEI 

recommends that the Commission 

clarify that it will grant an extension of 

time if the stakeholder process prevents 

an ISO or RTO from obtaining 

stakeholder approval of tariff changes 

within the 90-day deadline. SPP 

requests a minimum of 120 days for 

compliance. National Grid and MISO (in 

its reply comments) propose that the 

Commission establish a single deadline 

for ISOs/RTOs and their transmissionowning members set at six months from 

the date of publication of the Final Rule. 

Commission Determination 

157. The Commission adopts the 

compliance procedures proposed in the 

NOPR, with certain revisions and 

clarifications. We will require ISO and 

RTO transmission providers to submit 

FPA section 206 compliance filings, 

within 210 days after the publication of 

the Final Rule in the Federal Register, 

that contain the non-rate terms and 

conditions set forth in the Final Rule or 

that demonstrate that their existing tariff 

provisions are consistent with or 

superior to the revised provisions of the 

pro forma OATT. As with non-ISO/RTO 

transmission providers, however, we 

will not require ISO and RTO 

transmission providers to ‘‘rejustify’’

existing provisions in their OATTs that 

are not affected in a substantive manner 

by the revisions to the pro forma OATT 

in the Final Rule. As we explained 

above, we find that such a process is 

unnecessary, given that we have already 

found these provisions to be consistent 

with or superior to the Order No. 888 

pro forma OATT and these provisions 

are not substantively affected by the 

reforms we adopt today. 

158. We also recognize, as we did in 

the NOPR, that some of the changes 

adopted in the Final Rule may not be as 

relevant to ISO/RTO transmission 


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110For further information related to the Final 

Rule, such as electronic versions of the pro forma 

OATT showing tariff changes adopted in the Final 

Rule in redline/strikeout format, and further 

information regarding docketing of compliance 

filings and specific filing instructions, please visit 

our Web site at the following location http:// 

www.ferc.gov/industries/electric/indus-act/oattreform.asp. 

111These entities are not FPA public utilities and 

therefore are not subject to the Commission’s 

jurisdiction under sections 205 and 206 of the FPA. 

112See Order No. 888–A at 30,285–86. 

113For non-public utilities that choose to use the 

safe harbor tariff, the Commission noted in the 

NOPR that the existing safe harbor provisions 

would need to be substantially conforming or 

superior to the new pro forma OATT. A non-public 

utility that already has a safe harbor tariff would 

therefore be required to amend its tariff so that its 

provisions substantially conform or are superior to 

the new pro forma OATT if it wishes to continue 

to qualify for safe harbor treatment. As the 

Commission stated in Order No. 888–A, a nonpublic utility may limit the use of its voluntarily 

offered safe harbor reciprocity tariff only to those 

transmission providers from whom the non-public 

utility obtains open access service, as long as the 

tariff otherwise substantially conforms to the pro 

forma OATT. See Order No. 888–A at 30,289. 

114The Commission noted in the NOPR that LPPC 

has committed to voluntary compliance with a set 

of guidelines for the provision of comparable 

service under FPA section 211A. 

providers as they are to nonindependent transmission providers. 

For example, many ISOs and RTOs use 

bid-based locational markets and 

financial rights to address transmission 

congestion, rather than the first-come, 

first-served physical rights model set 

forth in the pro forma OATT. As we 

indicated in the NOPR, nothing in this 

rulemaking is intended to upset the 

market designs used by existing ISOs 

and RTOs. We also recognize that ISOs 

and RTOs may well have adopted 

practices that are already consistent 

with or superior to the reforms adopted 

here. For example, ISOs and RTOs tend 

to have transmission planning processes 

that are significantly more open and 

transparent than the processes used by 

non-independent transmission 

providers. We encourage ISOs and RTOs 

to meet with their stakeholders to 

discuss whether any improvements are 

necessary to comply with the Final 

Rule. 

159. We reject Indianapolis Power’s 

proposal to require tariff changes 

resulting from this rulemaking only 

with the support of the ISO and RTO 

members who may bear the costs 

associated with the revision. 

Indianapolis Power effectively asks that 

we allow ISO and RTO members to veto 

our decisions here, which is contrary to 

our duty to prevent undue 

discrimination in the provision of 

transmission service. 

160. Regarding CAISO’s request for 

clarification of how it should address 

changes in the Final Rule to 

transmission services that it does not 

provide or which are incompatible with 

its service model, we reiterate that 

CAISO—like any other ISO or RTO—has 

the opportunity to demonstrate that a 

variation from the tariff revisions 

adopted in the Final Rule satisfies the 

consistent with or superior to standard. 

We do not believe that the adoption of 

an ‘‘independent entity variation,’’

proposed by PJM, or a regional variation 

standard, proposed by Xcel and 

Indicated New York Transmission 

Owners, would be appropriate. Again, 

the Commission finds that the reforms 

adopted in this Final Rule are necessary 

to prevent undue discrimination in the 

provision of transmission service and 

any transmission provider, including an 

ISO or RTO, must demonstrate that 

variations from the tariff modifications 

required here satisfy the consistent with 

or superior to standard. 

161. As discussed above, however, we 

will align the compliance filing 

deadlines for ISOs and RTOs and their 

transmission-owning members and 

require public utility transmission 

owners whose transmission facilities are 

under the control of RTOs or ISOs to 

make any necessary tariff filings 

required to comply with the Final Rule 

within 210 days after the publication of 

the Final Rule in the Federal Register. 

A summary of the more significant filing 

requirements established in this Final 

Rule is provided in Appendix A.110

3. Non-Public Utility Transmission 

Providers/Reciprocity 

162. In Order No. 888, the 

Commission conditioned non-public 

utilities’ use of public utility open 

access services on an agreement to offer 

comparable transmission services in 

return.111 The Commission found that, 

while it did not have the authority to 

require non-public utilities to make 

their systems generally available, it did 

have the ability and the obligation to 

ensure that open access transmission is 

as widely available as possible and that 

Order No. 888 did not result in a 

competitive disadvantage to public 

utilities. 

163. Under the reciprocity provision 

in section 6 of the pro forma OATT, if 

a public utility seeks transmission 

service from a non-public utility to 

which it provides open access 

transmission service, the non-public 

utility that owns, controls, or operates 

transmission facilities must provide 

comparable transmission service that it 

is capable of providing on its own 

system. Under the pro forma OATT, a 

public utility may refuse to provide 

open access transmission service to a 

non-public utility if the non-public 

utility refuses to reciprocate. A nonpublic utility may satisfy the reciprocity 

condition in one of three ways. First, it 

may provide service under a tariff that 

has been approved by the Commission 

under the voluntary ‘‘safe harbor’’

provision. A non-public utility using 

this alternative submits a reciprocity 

tariff to the Commission seeking a 

declaratory order that the proposed 

reciprocity tariff substantially conforms 

to, or is superior to, the pro forma 

OATT. The non-public utility then must 

offer service under its reciprocity tariff 

to any public utility whose transmission 

service the non-public utility seeks to 

use. Second, the non-public utility may 

provide service to a public utility under 

a bilateral agreement that satisfies its 

reciprocity obligation. Finally, the nonpublic utility may seek a waiver of the 

reciprocity condition from the public 

utility.112

164. In EPAct 2005, Congress 

authorized, but did not require, the 

Commission to order non-public 

utilities (or ‘‘unregulated transmitting 

utilities’’) to provide transmission 

services under a new section 211A in 

Part II of the FPA. This section states in 

part that the Commission ‘‘may, by rule 

or order, require an unregulated 

transmitting utility to provide 

transmission services’’ at rates that are 

comparable to those it charges itself and 

under terms and conditions (unrelated 

to rates) that are comparable to those it 

applies to itself, and that are not unduly 

discriminatory or preferential. The 

language does not limit the Commission 

to ordering transmission services only to 

the public utility from whom the nonpublic utility takes transmission 

services, but rather permits the 

Commission to order the non-public 

utility to provide ‘‘open access’’

transmission service, i.e., service to all 

eligible customers. 

165. In the NOPR, the Commission 

proposed to retain the current 

reciprocity language in the pro forma 

OATT, as well as Order No. 888’s three 

alternative provisions for satisfying the 

reciprocity condition, i.e.: A non-public 

utility that owns, controls, or operates 

transmission and seeks transmission 

service from a public utility must either 

satisfy its reciprocity obligation under a 

bilateral agreement, seek a waiver of the 

OATT reciprocity condition from the 

public utility, or file a safe harbor tariff 

with the Commission.113

166. The Commission did not propose 

a generic rule to implement the new 

FPA section 211A.114 Rather, the 

Commission proposed to apply its 

provisions on a case-by-case basis, such 

as when a public utility seeks service 


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115E.g., APPA, Bonneville, LPPC, Newfoundland, 

NRECA, PGP, Sacramento, Salt River, Santa Clara, 

Santee Cooper, Seattle, TANC, TAPS, TVA, 

Tacoma, WAPA, CMUA Reply, East Texas 

Cooperatives Reply, Lassen Reply, and Public 

Power Council Reply. 

116See also Public Power Council Reply and 

Sacramento Reply. 

117E.g., AWEA, California Commission, Calpine, 

EEI, MidAmerican, San Diego G&E, and Xcel. 

118E.g., Calpine, MidAmerican, and Xcel. 

from an unregulated transmitting utility 

that has not requested service under the 

public utility’s OATT and the 

reciprocity obligation therefore does not 

apply. The Commission stated that such 

a customer may file an application with 

the Commission seeking an order 

compelling the unregulated transmitting 

utility to provide transmission service 

that meets the standards of FPA section 

211A. The Commission further 

proposed to amend its regulations to 

make clear that an applicant in an FPA 

section 211A proceeding against a nonpublic utility that has submitted an 

acceptable safe harbor tariff has the 

burden of proof to show why service 

under the safe harbor tariff is not 

sufficient and why an FPA section 211A 

order should be granted. In addition, the 

Commission stated in the NOPR its 

expectation that unregulated 

transmission providers would 

participate in the proposed open and 

transparent regional planning processes 

and noted that, if there were complaints 

about such participation, they would 

also be addressed on a case-by-case 

basis. 

167. The NOPR proposed to retain the 

existing reciprocity policy as applied to 

foreign utilities doing business in the 

United States, which we adopted 

pursuant to sections 205 and 206 of the 

FPA. By maintaining the same 

reciprocity requirement for these foreign 

utilities as for domestic, non-public 

utilities, the Commission stated that it 

would ensure that foreign entities will 

continue to be treated no less favorably 

than domestic, non-public utilities. 

Comments 

168. The majority of the commenters 

support the Commission’s decisions to 

retain the reciprocity provision and to 

adopt a case-by-case approach to FPA 

section 211A.115 These commenters 

reason that there is no evidence of a 

general problem of non-public utilities 

failing to provide transmission service 

and that, for the most part, non-public 

utilities already provide transmission on 

an as-available basis under comparable 

terms, regardless of whether a tariff is 

on file with the Commission. In 

addition, Santa Clara and TANC state 

that the Commission’s proposal 

apparently respects the 

nonjurisdictional status of public 

power. 

169. LPPC reiterates its prior offer of 

voluntary compliance with a set of 

guidelines for the provision of 

comparable open access service, which 

it contends will provide a significant 

degree of standardization for such 

service. Thus, LPPC believes that 

generic action under section 211A is not 

necessary. In addition, LPPC asserts that 

there is no evidence on record of undue 

discrimination by a nonjurisdictional 

entity that would justify the 

Commission reversing the NOPR 

decision to act on a case-by-case basis 

under FPA section 211A.116

170. On the other hand, several 

commenters urge the Commission to 

implement FPA section 211A on a 

generic basis.117 AWEA argues that 

reciprocity tariffs do not subject the 

nonpublic utilities to Commission 

enforcement as would an OATT 

established under FPA section 211A. 

AWEA urges the Commission to 

proceed on a generic basis to ensure that 

nonjurisdictional utilities comply with 

the reformed OATT under exactly the 

same terms and conditions as 

jurisdictional utilities. On reply, 

however, APPA argues that the 

comparability standard does not mean 

that unregulated transmitting utilities 

must comply with the reformed OATT 

under exactly the same terms and 

conditions as jurisdictional entities. 

171. In its reply comments, EEI states 

that, while LPPC’s voluntary proposal is 

a step in the right direction, LPPC’s 

proposal does not go far enough to 

assure that reciprocal transmission 

service is provided in a nondiscriminatory manner. EEI asserts that 

LPPC’s proposal still gives the 

individual non-public utility 

transmission provider the discretion to 

decide what is or is not comparable and 

not unduly discriminatory. Moreover, 

EEI notes, LPPC does not represent the 

universe of non-public utility 

transmission providers, rather only 24 

of the largest governmentally-owned 

transmission providers. 

172. Some commenters argue that the 

case-by-case approach proposed in the 

NOPR does not satisfy the Commission’s 

stated goal of remedying undue 

discrimination and its intent to provide 

transparent, consistent and clear rules 

for use of the nation’s transmission 

grid.118 Calpine contends that the 

administrative burden of monitoring 

and administering customer complaints 

or processing applications that seek to 

compel unregulated transmitting 

utilities in different parts of the country 

to provide comparable service would 

create a ‘‘patchwork of open and 

closed’’ unregulated transmitting 

utilities, just like the patchwork of open 

and closed jurisdictional transmission 

systems the Commission sought to 

eliminate when it issued Order No. 888. 

Calpine also states that its comments on 

the NOI in this proceeding provide 

several examples of the kinds of 

problems it has experienced in seeking 

transmission service from unregulated 

transmitting utilities in a variety of 

regions and across multiple 

transmission systems. 

173. California Commission argues 

that FPA section 211A gives the 

Commission the authority to require 

previously nonjurisdictional entities to 

file tariffs with the Commission that 

would be subject to the due process and 

the ‘‘just and reasonable’’ requirements 

of the FPA. California Commission 

urges the Commission to actively 

explore a set of mandatory actions that 

the Commission may impose on 

nonjurisdictional entities and states 

that, if the Commission is reluctant to 

do so in this proceeding, it should 

initiate a new rulemaking to consider 

such rules. California Commission 

asserts that there are a number of sound 

policy reasons for taking generic action 

to address the mandate of FPA section 

211A. First, it argues that Commission 

action would prevent the balkanization 

of the grid that can result if a 

nonjurisdictional transmission owner 

refuses to participate in an RTO or ISO 

whose service area surrounds, 

encompasses, or overlaps it. Second, 

California Commission argues that 

Congress has given the Commission 

explicit authority to require previously 

nonjurisdictional entities to provide 

transmission service on a nonpreferential and non-discriminatory 

basis. Finally, California Commission 

asserts, the Commission would be able 

to squarely address generic seams issues 

created by the existence of control areas 

operated by previously unregulated 

transmission owners and the ability of 

such entities to ‘‘free ride’’ on the 

systems and open access requirements 

of the jurisdictional entities. 

174. In its reply comments, CMUA 

contests California Commission’s 

assertion that those outside CAISO 

operations are ‘‘free riders.’’ CMUA 

notes that its members post their excess 

transmission capacity on wesTTrans (an 

OASIS site serving the Western 

Interconnection) thus making it 

available to third parties, and that its 

members outside the CAISO also pay a 


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119See also APPA Reply. 

120See also CMUA Reply and Santa Clara Reply. 

121 Xcel and MidAmerican support EEI’s proposal 

on this issue. 

122Citing Order No. 888–A at 30,287. 

host of CAISO fees.119 CMUA states that 

it does not contest that there are 

‘‘seams’’ between organized markets and 

neighbors, but it asserts that this docket 

is not the place for this discussion and 

FPA section 211A is not the remedy. In 

its reply comments, APPA also urges the 

Commission to reject California 

Commission’s proposal. APPA argues 

that section 211A was not intended, nor 

could the Commission use it, to require 

nonjurisdictional transmission 

providers to participate in an RTO and, 

therefore, California Commission’s 

proposal exceeds the Commission’s 

authority under section 211A.120

175. EPSA, in its reply comments, 

disagrees with commenters who appear 

to believe that nonjurisdictional 

transmitting utilities will not have to 

take any steps to comply with a final 

order in this rulemaking. EPSA states 

that its understanding is that the 

Commission’s principle of reciprocity 

would apply to any changes in the pro 

forma OATT adopted in the Final Rule. 

Accordingly, both jurisdictional and 

nonjurisdictional transmitting utilities 

that adopted the Order No. 888 pro 

forma OATT would have to make 

compliance filings. In addition, EPSA 

argues that nonjurisdictional 

transmitting utilities that previously 

received an Order No. 888 waiver or 

that wish to request such a waiver 

should have an affirmative duty to file 

a request for a waiver. In the event that 

a nonjurisdictional entity wishes to file 

a bilateral contract, EPSA contends that 

it should be required to file a 

‘‘reciprocity’’ contract pursuant to FPA 

section 205. If a nonjurisdictional 

transmitting utility does not adopt a 

revised pro forma OATT as a ‘‘safe 

harbor,’’ EPSA argues the Commission’s 

standard of review should be whether 

the nonjurisdictional transmitting 

utility’s alternative tariff is ‘‘equal or 

superior to’’ a revised pro forma OATT. 

176. EPSA, in its reply comments, 

supports implementing the rate 

provisions of FPA section 211A in a 

proceeding separate from this particular 

proceeding. EPSA states that such a 

proceeding could take a generic 

approach, in that nonjurisdictional 

transmitting utilities could be required 

to set transmission rates for third-party 

transmission services that are computed 

using rate determinants that are 

comparable to the determinants that the 

non-public utility uses to calculate 

transmission rates for its native load. 

177. With regard to specific 

reciprocity obligations, LPPC argues that 

the Commission should revise section 6 

of the pro forma OATT to reflect the 

comparability standards now contained 

in FPA section 211A. LPPC states that, 

with the implementation of FPA section 

211A, it is appropriate to revise the pro 

forma OATT language in order to reflect 

the unregulated utility’s obligation ‘‘to 

provide transmission service 

comparable to the service the customer 

provides itself’’ as the ‘‘quid pro quo’’

for receiving reciprocal service. LPPC 

also argues that, with respect to the 

existing safe harbor option, the 

Commission should revise its test for 

evaluating a safe harbor OATT from one 

which asks whether the proposal is 

equivalent or superior to the pro forma 

OATT, to one which asks whether the 

service provided under the proposed 

OATT is comparable to the service that 

the unregulated utility provides itself. 

178. EPSA replies that LPPC’s 

suggestion to revise the language of 

section 6 ironically would require 

nonjurisdictional transmitting utilities 

to offer third party customers 

transmission services that are 

comparable to network transmission 

service, which is a higher quality of 

transmission service than the revised 

OATT and which is unlikely to be 

supported by nonjurisdictional 

transmitting utilities. EPSA states that it 

believes that FPA section 211A requires 

a nonjurisdictional transmitting utility 

to provide transmission service (at its 

interfaces with jurisdictional public 

utilities and internal sources) that is 

comparable to the service it is taking at 

interfaces or internal sources. EPSA 

therefore argues that the appropriate 

standard for determining whether a 

nonjurisdictional transmitting utility’s 

tariff is comparable is whether the 

nonjurisdictional utility’s tariff is ‘‘equal 

or superior’’ to the revised pro forma 

OATT. 

179. LPPC also argues that the two 

categorical exemptions from FPA 

section 211A articulated in FPA section 

211A(c)(3) (based on size and the value 

of the unregulated system to the 

integrated grid) should not be exclusive. 

Rather, LPPC contends that the two 

exemptions should guide the 

Commission in considering similar 

requests for exemption. For example, 

LPPC argues that relatively small 

utilities, which nevertheless exceed an 

express threshold, should be permitted 

to demonstrate that their systems are 

simply too small, and that their facilities 

are not sufficiently strategic, to call for 

full inclusion in the FPA section 211A 

regime. Similarly, LPPC states that, in 

certain public systems, only some 

discrete portions of the system would 

fairly be considered part of the 

integrated system. In these cases as well, 

LPPC argues, it would make sense for 

the Commission to entertain requests for 

partial waiver. 

180. If the Commission does not 

reconsider its proposal not to act 

generically under FPA section 211A, 

EEI contends that there are other actions 

the Commission should take. In order to 

facilitate full compliance with the 

reciprocity obligation, EEI urges the 

Commission at least to clarify and 

strengthen the obligations of non-public 

utility transmission providers under the 

reciprocity provision,121 exercise 

oversight and monitor their compliance 

with the reciprocity obligation, and 

require them to provide greater 

transparency of the transmission 

services and the terms and conditions of 

service they offer so that those seeking 

transmission service under the 

reciprocity provision are able to 

determine whether they are complying 

with their reciprocity obligation. 

181. With respect to the reciprocity 

provision in the pro forma OATT, EEI 

requests that the Commission update it 

by including reference to transmission 

service by ISOs and RTOs. EEI asks that 

the reciprocity provision be modified to 

provide that, if an ISO or RTO is the 

transmission provider, the reciprocity 

obligation is owed to all members of the 

ISO or RTO. EEI notes, however, that 

even this action would not require nonpublic utility transmission providers to 

provide transmission services to other 

entities who are eligible customers 

under the ISO or RTO OATT and who 

are not transmission providers, such as 

independent generators. EEI asserts that 

non-public utility transmission 

providers may discriminate against 

certain transmission customers unless 

the reciprocity obligation is expanded. 

Sempra Global also asks the 

Commission to clarify that the right to 

seek transmission service from an 

unregulated transmitting utility 

pursuant to FPA section 211A is 

available to any entity that qualifies as 

an eligible customer under the 

Commission’s pro forma OATT. 

182. EEI acknowledges that the 

Commission declined in Order No. 888–

A to expand the reciprocity provision 

beyond the specific transmission 

provider from which the transmission 

customer takes service on the ground 

that requiring ‘‘non-public utilities to 

offer transmission service to entities 

other than public utility transmission 

providers increases the chances that 

they could lose tax-exempt status.’’ 122

However, EEI states, in 2002, the 


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123Treas. Reg. § 1.141–7(g). 124EEI asserts that the Commission also has the 

authority to make this change under FPA section 

211A, which provides that the Commission may not 

require a State or municipality to take action under 

that section that would violate a private utility bond 

rule. If a non-public utility transmission provider is 

concerned about the impact on the tax-exempt 

status of its bonds, EEI suggests that it could seek 

a waiver from the Commission. 

125Citing Order No. 888–A at 30,285. 

126According to EEI, the new authority granted to 

the Commission under EPAct 2005 section 1281 

(new FPA section 220) (Electricity Market 

Transparency Rules), which applies to all ‘‘market 

participants,’’ provides another basis for requiring 

greater transparency under the pro forma OATT by 

non-public utility transmission providers. EEI 

argues that the Commission could rely on this new 

authority to require greater transparency in 

transmission service provided under the reciprocity 

obligation. 

127EEI notes that, in the NOPR, the Commission 

referenced voluntary guidelines being developed by 

members of the LPPC. EEI believes this is a step in 

the right direction and looks forward to the 

opportunity to provide input on the proposed 

guidelines. In EEI’s view, however, if any LPPC 

member wishes to use these guidelines as a safe 

harbor tariff, it must meet the safe harbor standard 

that the terms of service must be ‘‘substantially 

conforming or superior to’’ the revised OATT. The 

reciprocity obligation requires that the terms and 

conditions of service be comparable to those that 

the non-public utility transmission provider applies 

to itself and not be unduly discriminatory. 

128EEI states that this informational filing should 

include information such as: whether or not they 

have a reciprocity or other tariff and how it can be 

obtained, whether they have an OASIS and location 

URL, whether they have standards of conduct and 

where they are posted, whether they have posted 

business practices, their contact for regional 

transmission planning, and their ATC methodology. 

129Section 211A authorizes the Commission to 

require certain unregulated transmitting utilities to 

provide transmission services at rates that are 

comparable to those that the unregulated 

transmitting utilities charges itself and on terms and 

conditions (not related to rates) that are comparable 

to those under which the unregulated transmitting 

utility provides transmission services to itself and 

that are not unduly discriminatory or preferential. 

130E.g., APPA Reply, CMUA Reply, LPPC Reply, 

Lassen Reply, NRECA Reply, Sacramento Reply, 

and TANC Reply. 

Department of the Treasury adopted 

final regulations that in effect provide 

that providing open access transmission 

does not constitute private use.123

Therefore, EEI argues, this reason for 

limiting the services provided under the 

reciprocity obligation is no longer 

applicable.124

183. Moreover, EEI argues, as 

originally established in Order Nos. 888 

and 888–A, the Commission stated that 

it was ‘‘conditioning the use of public 

utility open access tariffs, by all 

customers including non-public 

utilities, on an agreement to offer 

comparable (not unduly discriminatory 

services) in return.’’ 125 However, EEI 

states, the reciprocity provision of the 

pro forma OATT refers to ‘‘similar terms 

and conditions’’ but does not make clear 

what they should be ‘‘similar’’ to. EEI 

argues that the term ‘‘similar’’ does not 

necessarily encompass the requirement 

that is part of comparability that the 

services provided be ‘‘not unduly 

discriminatory’’ as Order Nos. 888 and 

888–A require. EEI proposes that the pro 

forma OATT be amended to refer to 

‘‘comparable terms and conditions’’

rather than ‘‘similar’’ to align it with 

Order Nos. 888 and 888–A. Finally, EEI 

also states that the Commission should 

also reaffirm that the reciprocity 

obligation is binding on Canadian 

utilities. 

184. On reply, APPA urges the 

Commission to reject EEI’s proposed 

expansion of the reciprocity provision. 

APPA notes that EEI’s proposed 

application of the reforms to all nonpublic utility transmission providers 

would potentially include a broader 

universe of public power entities than 

those subject to FPA section 211A. 

Moreover, APPA argues, many of the 

goals that EEI claims it wishes to 

accomplish would be accomplished 

even if the Commission takes no action. 

185. In its reply comments, the 

Canadian Electricity Association urges 

the Commission to reject EEI’s proposal 

to strengthen the reciprocity obligation 

so as to require the offering of 

transmission service to all eligible 

customers. The Canadian Electricity 

Association argues that the effect of 

EEI’s proposal would be to enable a 

generator generating power in Canada to 

obtain access on a Canadian utility’s 

transmission system, which is not the 

situation under the current reciprocity 

requirement. Consequently, the 

Canadian Electricity Association asserts, 

EEI’s proposal would allow the 

Commission to fully impose open access 

requirements in Canada and would 

violate the principles of comity and 

undermine Canadian jurisdictional 

sovereignty. 

186. The Canadian Electricity 

Association also repeats its earlier 

arguments made in response to the NOI 

that, to the extent the Commission 

adopts the comparability standard in 

FPA section 211A for non-public 

utilities, the Commission must apply 

the same changes to Canadian utilities. 

187. EEI also urges the Commission to 

take certain steps to increase 

transparency and accountability in 

complying with the reciprocity 

requirement.126 For example, EEI states, 

the Commission could include on its 

Web site a list of all non-public utility 

transmission providers that have 

Commission-approved safe harbor 

reciprocity tariffs. According to EEI, 

such a list of entities would facilitate 

use of their transmission systems, 

provide transparency, and provide 

recognition to these entities for their 

voluntary efforts in accomplishing these 

goals.127

188. EEI requests that the Commission 

also establish minimal transparency 

requirements for non-public utility 

transmission providers.128 EEI asserts 

that the Commission has ample 

authority under FPA section 211A and 

under the reciprocity provision of the 

pro forma tariff to apply this 

information reporting requirement to 

those large non-public utility 

transmission providers that are not 

exempted by section 211A(c).129

189. On reply, several commenters 

oppose EEI’s transparency proposal. 

Among other things, they argue that 

EEI’s proposal is unnecessary and 

duplicative of information that is 

already publicly available—e.g., the 

non-public utility’s Web site, the 

Commission’s Web site, or in some 

instances a regional entity’s Web site 

(such as the wesTTrans OASIS).130

APPA further notes that LPPC has 

proposed that the terms and conditions 

in non-public utility transmission 

provider’s tariffs would be publicly 

available on the individual utility’s or a 

regional entity’s Web site. In addition, 

NRECA asserts that, absent waivers, any 

non-public utility transmission provider 

that has adopted a ‘‘safe-harbor’’ tariff 

has adopted all of the OATT, OASIS, 

and Standards of Conduct requirements 

that apply to public utilities. NRECA 

and TANC both assert that the 

Commission does not have similar 

informational filing requirements for 

public utilities. Furthermore, TANC 

argues that it would be a waste of 

Commission resources to compile a list 

of all non-public utility transmission 

providers that have Commissionapproved safe harbor tariffs. TANC also 

argues that to provide such an 

information filing would be unduly 

burdensome and a waste of 

nonjurisdictional utility transmission 

provider time and limited resources. 

Commission Determination 

190. The Commission retains the 

reciprocity language in the Order No. 

888 pro forma OATT, but updates it to 

include references to ISOs and RTOs, as 

suggested by EEI. We also modify the 

reciprocity provision to provide that, if 

an ISO or RTO is the transmission 

provider, the reciprocity obligation is 

owed to all members of that ISO or RTO. 

We concur with EEI’s assessment that 

such modifications will more accurately 

reflect the current state of the industry. 

However, we will not adopt EEI’s 

proposal to extend the reciprocity 

obligation to all eligible customers or 


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131See Order No. 888–A at 30,289. 

132See revised 18 CFR 35.28(e)(1)(ii). 

133All references to NERC in the context of 

developing reliability standards are to NERC as the 

Electric Reliability Organization (ERO). 

134We note that many of the ATC-related 

reliability standards filed in Docket No. RM06–16–

000 were not addressed by the NOPR in that 

proceeding, pending the submittal of additional 

information. See Mandatory Reliability Standards 

for the Bulk-Power System, 71 FR 64770 (Nov. 3, 

2006), FERC Stats. & Regs. ¶ 32,608 at Appendix A 

(2006) (Reliability Standards NOPR). 

135The ATC components are total transfer 

capability (TTC), existing transmission 

commitments (ETC), capacity benefit margin (CBM), 

and transmission reserve margin (TRM). 

LPPC’s proposal to revise the pro forma 

OATT language regarding 

comparability. We are not persuaded 

that either proposal is necessary at this 

time to prevent undue discrimination 

absent a complaint. 

191. We will also retain Order No. 

888’s three alternative provisions for 

satisfying the reciprocity condition, i.e.: 

A non-public utility that owns, controls, 

or operates transmission and seeks 

transmission service from a public 

utility must either satisfy its reciprocity 

obligation under a bilateral agreement, 

seek a waiver of the OATT reciprocity 

condition from the public utility, or file 

a safe harbor tariff with the 

Commission. Thus, for non-public 

utilities that choose to use the safe 

harbor tariff, its provisions must be 

substantially conforming or superior to 

the revised pro forma OATT in this 

Final Rule. A non-public utility that 

already has a safe harbor tariff must 

amend its tariff so that its provisions 

substantially conform or are superior to 

the revised pro forma OATT if it wishes 

to continue to qualify for safe harbor 

treatment. As the Commission stated in 

Order No. 888–A, a non-public utility 

may limit the use of its voluntarily 

offered safe harbor reciprocity tariff only 

to those transmission providers from 

whom the non-public utility obtains 

open access service, as long as the tariff 

otherwise substantially conforms to the 

pro forma OATT.131 We reiterate that 

these reciprocity requirements apply 

equally to all non-public utility 

transmission providers, including those 

located in foreign countries. 

192. As the Commission proposed in 

the NOPR, we will not adopt a generic 

rule to implement the new FPA section 

211A. Rather, we will apply its 

provisions on a case-by-case basis, such 

as when a public utility seeks service 

from an unregulated transmitting utility 

that has not requested service under the 

public utility’s OATT and the 

reciprocity obligation therefore does not 

apply. A potential customer may file an 

application with the Commission 

seeking an order compelling the 

unregulated transmitting utility to 

provide transmission service that meets 

the standards of FPA section 211A. We 

adopt the NOPR proposal to amend our 

regulations to make clear that an 

applicant in an FPA section 211A 

proceeding against a non-public utility 

that has submitted an acceptable safe 

harbor tariff shall have the burden of 

proof to show why service under the 

safe harbor tariff is not sufficient and 

why an FPA section 211A order should 

be granted.132 Further, as we indicate 

below, we restate our expectation that 

unregulated transmission providers will 

participate in the open and transparent 

regional planning processes ordered 

below and note that, if there are 

complaints about such participation or 

the lack thereof, we will address them 

on a case-by-case basis. 

V. Reforms of the OATT 

A. Consistency and Transparency of 

ATC Calculations 

193. In the NOPR, the Commission 

proposed to take action under FPA 

section 206 to remedy undue 

discrimination in the provision of 

transmission service. The Commission 

recognized that while Order Nos. 888 

and 889 require transmission providers 

to offer and post any available transfer 

capability (ATC) on their OASIS, and 

file the methodology they use to 

calculate ATC as Attachment C to their 

OATTs, the industry has not developed 

a consistent methodology for evaluating 

ATC nor have transmission providers 

adequately made their ATC calculation 

methodology transparent. This 

inconsistency and lack of transparency 

creates the potential for undue 

discrimination in the provision of open 

access transmission service. 

194. In the NOPR, the Commission 

proposed to address this potential for 

undue discrimination by requiring 

industry-wide consistency and 

transparency of all components of the 

ATC calculation methodology and 

certain definitions, data, and modeling 

assumptions. The Commission proposed 

to provide guidance regarding aspects of 

ATC calculations that should be more 

consistent and proposed to direct public 

utilities, working through NERC133 and 

NAESB, to revise reliability standards 

and business practices that are relevant 

to ATC calculations. The Commission 

also proposed to require increased detail 

in Attachment C of each transmission 

provider’s OATT and proposed 

amending the OASIS regulations to 

require increased transparency. 

Although commenters challenged 

aspects of this proposed remedy, no 

commenters challenged the underlying 

finding that ATC reform is necessary to 

remedy undue discrimination in the 

provision of transmission service. 

195. The Commission also indicated 

that the lack of consistent, industrywide ATC calculation standards poses a 

threat to the reliable operation of the 

bulk-power system, particularly because 

a transmission provider may not know 

of its neighbors’ system conditions 

affecting its own ATC values. As a result 

of this reliability impact, the 

Commission observed that the proposed 

ATC reforms are also supported by FPA 

section 215(d)(5), through which the 

Commission has the authority to direct 

the ERO to submit a reliability standard 

that the Commission considers 

appropriate to implement FPA section 

215. 

196. In light of these concerns, we 

direct public utilities, working through 

NERC reliability standards and NAESB 

business practices development 

processes, to produce workable 

solutions to complex and contentious 

issues surrounding improving the 

consistency and transparency of ATC 

calculations. We are directing our 

guidance to public utilities and require 

that they implement our direction by 

working with NERC to develop 

reliability standards that accomplish the 

ATC reforms required in this 

rulemaking. We will coordinate our 

directives here with the ATC-related 

reliability standards that are pending in 

Docket No. RM06–16–000.134 The 

specifics of our findings with respect to 

ATC reform are discussed below. 

1. Consistency 

197. In order to address the potential 

for remaining undue discrimination in 

the determination of ATC, the 

Commission proposed to require 

industry-wide consistency of certain 

definitions, data, and modeling 

assumptions of the ATC calculation. 

a. Necessary Degree of Consistency 

NOPR Proposal 

198. In the NOPR, the Commission 

recognized that transmission providers 

use several basic types of ATC 

calculation methodologies (with various 

permutations), and did not propose to 

require a single ATC calculation 

methodology to be applied by all 

transmission providers. However, the 

Commission proposed to achieve greater 

consistency in ATC calculations by 

directing the development of consistent 

definitions of the ATC components,135

as well as consistent data inputs, 

modeling assumptions, and data 


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136E.g., Alcoa, Alliance, Ameren, Arkansas 

Commission, Arkansas Municipal, AWEA, Duke, 

E.ON, EEI, ELCON, EPSA, Exelon, LDWP, 

MidAmerican, NRECA, NPPD, NERC, Occidental, 

Powerex, PJM, PPL, Progress Energy, Project for 

Sustainable FERC Energy Policy, Santee Cooper, 

Southern, Suez Energy NA, SPP, TAPS, TVA, TDU 

Systems, TranServ, Tacoma, TANC, WECC, 

WestConnect, and Xcel. 

137E.g. Allegheny, Entergy, Indianapolis Power, 

North Carolina Agencies, and NARUC. 

138E.g. Bonneville, Northwest IOUs, and 

NorthWestern. 

139E.g. CAISO. 

140E.g. Ameren and Tacoma. 

141E.g. APPA, Barrick Reply, Duke, EEI, Imperial, 

International Transmission, LDWP, NARUC, 

Nevada Companies, New York Commission, 

NRECA, MidAmerican, Occidental Reply, Pinnacle, 

PNM-TNMP, Public Power Council, CREPC, Salt 

River, Seattle, South Carolina E&G Reply, SPP 

Reply, Utah Municipals, and WPS Companies 

Reply. 

142E.g. TDU Systems and East Texas Cooperatives 

Reply. 

143E.g., ATC = TTC ¥ (ETC + CBM + TRM). 

144E.g., EEI Reply, NARUC Reply, and Powerex 

Reply. 

145Transcript of October 12 Technical Conference 

at 125–150. 

146MOD standards refers to Modeling, Data, and 

Analysis Reliability Standards. 

147Transcript of October 12 Technical Conference 

at 149–160. 

exchange and coordination protocols. 

The Commission also required each 

transmission provider using an 

Available Flowgate Capacity (AFC) 

methodology to explain its definition of 

AFC, its calculation methodology and 

assumptions, and its process for 

converting AFC into ATC. 

Comments 

199. While the majority of 

commenters 136 support the NOPR’s 

proposal to increase consistency in the 

calculation of ATC, several caution the 

Commission to allow flexibility 137 in 

order to capture differences in system 

operations,138 usage, market 

operations,139 and topology. Many 

assert that industry-wide 

standardization of the ATC calculation 

might not be possible and suggest that 

the Commission consider 

interconnection-wide,140 regional,141 or 

even sub-regional standardization. 

NARUC urges the Commission to 

facilitate State commission participation 

in efforts to reform ATC methodologies 

and calculations on a regional or subregional basis. Conversely, several 

commenters suggest that, if the 

Commission considers allowing use of 

different ATC calculations, it must 

impose a heavy burden on any entity 

seeking to justify a departure from the 

interconnection-wide or regional ATC 

standard.142

200. Constellation proposes that the 

Final Rule establish a rebuttable 

presumption that the basic ATC 

calculation formula 143 set forth in 

NERC’s current ATC definition be 

identical within a region and that each 

element of the calculation have the 

same meaning for all transmission 

providers. Williams requests on reply 

that the Commission establish an 

industry-wide standard for the 

calculation of ATC and emphasizes that 

a consistent and transparent approach to 

evaluating ATC and ATC/AFC modeling 

assumptions is a prerequisite to the 

elimination of the broad discretion 

afforded transmission providers and, 

with it, the subtle discrimination 

practiced against customers. 

201. Southern suggests that the basic 

ATC calculation should be defined for 

both firm and non-firm ATC 

calculations and also proposes that the 

following basic formulas be used: ATC 

(firm) = TTC¥ Firm Commitments or 

ETC ¥ TRM ¥ CBM; and ATC (nonfirm) = TTC¥ Firm and Nonfirm 

Commitments + Postbacks of Redirected 

and Unscheduled 

Service ¥ TRM ¥ CBM. In addition, 

TDU Systems requests that the 

Commission require standardization of 

methods for calculating AFC and 

require NERC to create a formal 

definition of AFC. 

202. PNM–TNMP and Bonneville 

express concerns with imposing an 

industry-wide standardized ATC 

methodology, arguing that there are too 

many variables in the way systems are 

operated. In its reply comments, PNM–

TNMP adds that NERC’s ATC 

calculation method should take into 

consideration the need for regional 

variation, and focus on consistency in 

definitions and data inputs. 

WestConnect participants caution that 

the replacement of the contract path 

ATC approach used in the Western 

Electricity Coordinating Council 

(WECC) with a flowgate methodology 

could seriously disrupt transmission 

service in the Western Interconnection. 

203. PGP states that, although regional 

and sub-regional consistency is a good 

idea, there is no need for the 

Commission to require ‘‘consistent’’

ATC methodologies; rather, the 

emphasis should be on transparency of 

the methodologies, inputs, calculations 

and outputs. Other commenters agree 

that the Commission should not require 

overall standardization of ATC 

calculations, but instead permit regional 

differences with respect to certain 

aspects of the calculation of ATC.144 EEI 

argues that standardization of ATC 

methodologies would require 

transmission systems to adopt a ‘‘lowest 

common denominator’’ standard in 

order to ensure that system reliability is 

not compromised, which would result 

in a reduction in ATC. EEI suggests that 

the Commission should direct NERC to 

develop ATC calculation standards that 

incorporate regional variations in order 

to maximize confidence in standards 

and system use, and maintain 

reliability. In its reply comments, 

Exelon disagrees with EEI and states 

that there are no regional differences 

within the individual interconnections 

that would justify differences in the 

application of ATC calculations. 

204. Exelon states that ATC 

definitions must be consistent so that 

the various ATC components such as 

TRM have the identical meaning for all 

industry participants. In addition, 

Exelon argues that each ATC component 

(ETC, TRM, and CBM) must be used in 

the same manner for all purposes (e.g., 

granting transmission service to third 

parties or for the transmission 

provider’s own network load). 

205. At the October 12 Technical 

Conference, NERC recognized that the 

goal of achieving consistency may not 

mean that a single ATC methodology is 

required.145 NERC explained that 

consistency can be achieved with a 

limited number of methodologies if the 

requirements of those methodologies are 

properly coordinated and 

communicated. NERC stated that the 

Standard Drafting Team modifying the 

modeling, data, and analysis (MOD) 

standards146 relevant to ATC is 

developing a standard applicable to 

three ATC calculation methodologies: 

the rated system path methodology 

(contract path), the network response 

methodology (network ATC), and the 

network response flowgate methodology 

(network AFC). NERC and the other 

panelists agreed that the two network 

methodologies are very similar in 

technique. NERC argued that the 

ultimate goal of ATC-related reforms 

should be to standardize definitions. 

The entire panel agreed that definitions 

must be consistent and a panelist 

representing Constellation asserted that 

broad differences in the core definitions 

of the ATC calculation are neither 

rational nor explainable.147

206. New Mexico Attorney General 

recommends that the Commission allow 

a utility to waive the requirement to 

make certain elements of ATC more 

consistent if the utility can show that it 

is making adequate progress towards 

developing consistent and transparent 

ATC calculations at the sub-regional 

level. 

Commission Determination 

207. The Commission adopts the 

NOPR proposal to require industry-wide 


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148For example, utilities A and B would agree 

that ATC is derived by reducing TTC by the sum 

of ETC, CBM and TRM, but utility A may define 

ETC to include set-asides for contingencies while 

utility B may not. 

149See Transcript of October 12, 2006 Technical 

conference at 125. Thee three methodologies are 

different computational processes to determine a 

transmission system’s ATC. The first, contract path, 

examines TTC for every A-to-B path on the system 

in concert with all others, reduces ATC by path for 

ETC, TRM, and CBM, as appropriate, and produces 

ATC for each path. The second method, net work 

ATC, uses a simulator to look not at each path, but 

each transmission element (line, substation, etc.,), 

and rule first contingency simulations to establish 

ATC on a network basis. The third method, network 

AFC, uses a simulator to examine critical flowgates 

over a wider area, then requires a second step to 

convert AFC values to particular path ATC values. 

150The NERC ATC definition does not 

differentiate firm and non-firm ATC from a high 

level generic ATC definition: ‘‘A measure of the 

transfer capability remaining in the physical 

transmission network for further commercial 

activity over and above already committed uses. It 

is defined as Total Transfer Capability less existing 

transmission commitments (including retail 

customer service), less a Capacity Benefit Margin, 

less a Transmission Reliability Margin.’’ See North 

American Electric Reliability Corporation, Glossary 

of Terms Used in Reliability Standards (February 7, 

2006). 

consistency of all ATC components and 

certain definitions, data, and modeling 

assumptions. The Commission also will 

require each transmission provider to 

include in Attachment C to its OATT 

detailed descriptions for calculating 

both firm and non-firm ATC, consistent 

with the requirements of this Final Rule. 

The purpose of increasing the 

consistency and transparency of ATC 

calculations is to reduce the potential 

for undue discrimination in the 

provision of transmission service, 

specifically by reducing the opportunity 

for transmission providers to exercise 

excessive discretion. We find that the 

amount of discretion in the existing 

ATC calculation methodologies gives 

transmission providers the ability and 

opportunity to unduly discriminate 

against third parties. In order to 

minimize this discretion, the Final Rule 

requires that all ATC components (i.e., 

TTC, ETC, CBM, and TRM) and certain 

data inputs, data exchange, and 

assumptions be consistent and that the 

number of industry-wide ATC 

calculation formulas be few in number, 

transparent and produce equivalent 

results. The Commission finds that 

these reforms will facilitate 

development of a more coherent and 

uniform determination of ATC. 

208. We reject requests to establish a 

single methodology for calculating ATC, 

however, for several reasons. It is not 

our intent to require transmission 

providers to incur the expense of 

developing and adopting a new onesize-fits-all software package to 

calculate ATC. We also see little benefit 

in requiring a ‘‘lowest common 

denominator’’ ATC calculator. While a 

uniform methodology may result in all 

transmission providers calculating ATC 

in an identical manner, it would also 

likely lead to software implementation 

costs in excess of the resulting benefits. 

More importantly, we find that the 

potential for discrimination does not lie 

primarily in the choice of an ATC 

calculation methodology, but rather in 

the consistent application of its 

components. 

209. All ATC calculation 

methodologies derive ATC by modeling 

the system to establish TTC, expressed 

in terms of contract paths or flowgates, 

and reducing that figure by existing 

transmission commitments (i.e., ETC), a 

margin that recognizes uncertainties 

with transfer capability (i.e., TRM), and 

a margin that allows for meeting 

generation reliability criteria (i.e., CBM). 

These calculation methodologies are 

developed based on physical 

characteristics of the transmission 

provider’s transmission system, 

historical modeling practices, and 

processes developed for collection of 

input data related to transmission 

provider’s own system conditions as 

well as relevant data that model 

neighboring systems’ conditions. We 

therefore find that it is not the 

methodologies for calculating ATC 

themselves that create the opportunity 

for undue discrimination. Instead, we 

find that the potential for undue 

discrimination stems from two main 

sources: 

(1) Variability in the calculation of the 

components that are used to determine 

ATC and (2) the lack of a detailed 

description of the ATC calculation 

methodology and the underlying 

assumptions used by the transmission 

provider.148 The combination of a lack 

of consistency of the components of the 

ATC calculation coupled with the lack 

of transparency leaves customers and 

regulators unable to verify ATC 

calculations and may allow 

transmission providers to calculate ATC 

in different ways for different 

customers. 

210. Accordingly, we conclude that 

industry-wide consistency of all ATC 

components (TTC, ETC, CBM, and 

TRM) and certain data inputs and 

exchange, modeling assumptions, 

calculation frequency, and coordination 

of data relevant for the calculation of 

ATC will reduce the opportunities for 

the exercise of discretion that may lead 

to undue discrimination against 

unaffiliated transmission customers. 

The Commission understands that 

NERC currently is developing standards 

for three ATC calculation methodologies 

(contract or rating path ATC, network 

ATC, and network AFC).149 If all of the 

ATC components and certain data 

inputs and assumptions are consistent, 

the three ATC calculation 

methodologies being finalized by NERC 

through the reliability standards 

development process will produce 

predictable and sufficiently accurate, 

consistent, equivalent, and replicable 

results. It is therefore not necessary to 

require a single industry-wide ATC 

calculation methodology. The 

Commission instead concludes that use 

of the ATC calculation methodologies 

included in reliability standards 

currently being developed by NERC is 

acceptable. 

211. As TDU Systems note, there is 

neither a definition of AFC in NERC’s 

Glossary nor an existing reliability 

standard that discusses the AFC 

method. In order to achieve consistency 

in each component of the ATC 

calculation (discussed below), we direct 

public utilities, working through NERC, 

to develop an AFC definition and 

requirements used to identify a 

particular set of transmission facilities 

as a flowgate. However, we remind 

transmission providers that our 

regulations require the posting of ATC 

values associated with a particular path, 

not AFC values associated with a 

flowgate. Transmission providers using 

an AFC methodology must therefore 

convert flowgate (AFC) values into path 

(ATC) values for OASIS posting. In 

order to have consistent posting of the 

ATC, TTC, CBM, and TRM values on 

OASIS, we direct public utilities, 

working through NERC, to develop in 

the MOD–001 standard a rule to convert 

AFC into ATC values to be used by 

transmission providers that currently 

use the flowgate methodology. 

212. The Commission also believes 

that further clarification is necessary 

regarding the calculation algorithms for 

firm and non-firm ATC.150 Currently, 

NERC has no standards for calculating 

non-firm ATC. We find that the same 

potential for discrimination exists for 

non-firm transmission service as for 

firm service and that greater uniformity 

in both firm and non-firm ATC 

calculations will substantially reduce 

the remaining potential for undue 

discrimination. Therefore, we direct 

public utilities, working through NERC, 

to modify related ATC standards by 

implementing the following principles 

for firm and non-firm ATC calculations: 

(1) For firm ATC calculations, the 

transmission provider shall account 

only for firm commitments; and (2) for 

non-firm ATC calculations, the 


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151E.g., Allegheny, APPA, Arkansas Commission, 

Bonneville, CAISO, Constellation, E.ON, EEI, 

ELCON, Entergy, Exelon, FirstEnergy, LPPC, 

MidAmerican, New York Commission, NERC, 

Northeast Utilities, Project for Sustainable FERC 

Energy Policy, PNM–TNMP, Santa Clara, Southern, 

Tacoma, TransServ, and Utah Municipals. 

152E.g., EPSA and Williams. 

153Citing Standards for Business Practices and 

Communication Protocols for Pub. Utils., Order No. 

676, 71 FR 26199 (May 4, 2006), FERC Stats. & Regs. 

¶ 31,216 (2006), order on reh’g, Order No. 676–A, 

116 FERC ¶ 61,255 (2006). 

154Citing id. at P 20. 

155E.g., Constellation, Duke, EEI, Exelon, LPPC, 

MidAmerican, NARUC, Northwest IOUs, Public 

Power Council, CREPC, Southern, TDU Systems, 

and WestConnect. 

156E.g., Utah Municipals and Entegra. 

157Citing Long-Term AFC/ATC Task Force Final 

Report (Revised April 14, 2005), available at 

http://www.nerc.com/∼filez/ltatf.html. 

158E.g., Alcoa, Fayetteville, and MISO. 

transmission provider shall account for 

both firm and non-firm commitments, 

postbacks of redirected services, 

unscheduled service, and counterflows. 

We understand that these principles are 

currently followed by most transmission 

providers and believe they should be 

clearly set forth in the ATC-related 

reliability standards. As described 

below, each transmission provider’s 

Attachment C must include a detailed 

formula for both firm and non-firm 

ATC, consistent with the modified ATCrelated reliability standards. 

213. We deny New Mexico Attorney 

General’s request to grant waiver of the 

ATC consistency requirements to 

utilities that can show that they are 

making adequate progress toward 

developing consistent and transparent 

ATC calculations at the sub-regional 

level. While we certainly encourage 

regional consistency with respect to the 

ATC calculation methodology, we are 

not requiring consistency; therefore a 

waiver is not necessary. As discussed in 

more detail below, any request for 

waiver from these ATC calculation 

requirements must take place through 

the NERC reliability standards 

development process as a request for a 

regional difference, since the ATC 

requirements will be determined 

through the NERC reliability standards. 

b. Process To Achieve Consistency 

NOPR Proposal 

214. In the NOPR, the Commission 

expressed confidence that the existing 

NERC and NAESB processes were wellsuited to achieving greater consistency 

in ATC calculations. The Commission 

therefore proposed to require public 

utilities, working through NERC and 

NAESB, to revise the reliability 

standards and business practices 

relating to ATC, consistent with the 

guidance provided in the Final Rule, 

within 180 days after the publication of 

the Final Rule in the Federal Register. 

Comments 

215. Many commenters support the 

Commission’s proposal directing NERC 

and NAESB to develop reliability 

standards and business practices 

addressing ATC.151 In addition, several 

commenters urge the Commission to be 

more precise in differentiating between 

policy and business standards, and urge 

the Commission to provide more 

guidance to NERC and/or NAESB.152

NRECA suggests that the Commission 

require NERC and NAESB to file the 

results of their processes with the 

Commission, give all interested parties 

an opportunity to comment on the 

proposals, and exercise its independent 

authority to review, and if necessary, 

remand the issues or proposals back to 

NERC and NAESB. 

216. Occidental states on reply that it 

does not oppose NERC having a role in 

developing the basic requirements and 

standards for ATC. However, Occidental 

also urges the Commission to adopt a 

process similar to that employed in 

developing the Standards for Business 

Practices and Communication Protocols 

for Public Utilities, which were 

incorporated by reference into the pro 

forma OATT.153 There, the Commission 

allowed NAESB’s Wholesale Electric 

Quadrant to develop, with widespread 

industry input, business practice 

standards that the Commission then 

reviewed, adopted and required public 

utilities to include in their OATTs by 

reference.154 Occidental claims that this 

process would ensure industry input in 

the development of the methodology for 

ATC calculations, as well as 

Commission review and approval of the 

methodology. 

217. Several commenters raise 

concerns that six months may not be 

sufficient time to develop ATC-related 

reliability standards and business 

practices.155 Exelon, MidAmerican and 

NARUC propose that the Commission 

grant NERC one year from the date of 

the Final Rule to develop the necessary 

reliability standards. NARUC agrees 

with one year, but requests flexibility to 

assure that the NERC and NAESB 

processes can be adequately completed. 

NERC also states that it expects the 

standards development process, already 

underway, to be finalized with 

standards submitted to the Commission 

prior to the summer of 2007. LPPC 

recommends that, within six months of 

the issuance of the Final Rule, NERC be 

required to submit a progress report 

addressing the status and a work plan 

for conclusion within the ensuing six 

months. NRECA proposes that the 

Commission closely monitor the NERC 

and NAESB process. Some commenters 

strongly oppose a flexible deadline, and 

urge the Commission to establish a firm 

deadline that must be met.156

218. At the October 12 Technical 

Conference, NERC informed 

participants that a great deal of progress 

has been made since the proposed 

standards developed by the NERC 

Standard Committee in February 2006 

were generated to address the 

recommendations made by the LongTerm AFC/ATC Task Force.157

However, NERC indicates that a 

significant amount of work remains 

before the standard revisions are 

considered complete. Since NERC 

would like to finalize its revised 

standards for submittal to the 

Commission for the summer of 2007, 

NERC has established an aggressive 

schedule of meetings for drafting which 

will be coordinated with NAESB. 

219. PJM outlines several guidelines it 

suggests the Commission should give to 

NERC and NAESB regarding the 

standards development process and 

recommends that Commission staff 

participate in the standards 

development process. Williams and 

EPSA likewise request that the 

Commission provide clear guidance to 

NAESB to assure efficiency and 

timeliness of the process. 

220. Some commenters prefer 

engagement of a fully independent 

organization to develop standards and 

practices related to ATC.158 EPSA 

strongly urges the Commission to 

require all transmission providers 

outside of RTO areas to contract with an 

independent entity to develop and/or 

monitor ATC calculations. Although 

TDU Systems agree with EPSA that 

vertically-integrated transmission 

providers that are not subject to the 

independent oversight of an ISO/RTO 

retain inherent incentives to 

discriminate against competitors, they 

contend that the benefit of independent 

oversight of ATC calculations must be 

weighed against the cost of that 

oversight. Alcoa suggests engaging the 

Institute of Electrical and Electronics 

Engineers (IEEE) instead of the 

Commission’s proposal to use NERC 

and NAESB. APPA opposes that 

position. New York Commission 

proposes that regional reliability 

organizations, rather than NERC, 

complete this task and that the ATC 

calculators be closely coordinated by 


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159 If ISOs and RTOs cannot perform the 

coordination function, New York Commission 

suggests the establishment of a Transmission 

Oversight Center to oversee the calculation of ATC 

within and between ISOs and RTOs. 

160NAESB’s work plan for developing business 

practices related to other reforms adopted in this 

Final Rule should be filed separately, as requested 

in Section IV.C.1. 

161E.g., PJM and MISO Transmission Owners, 

SPP Reply. 

162E.g., ISO/RTO Council, ISO New England, and 

Pennsylvania Commission. 

163E.g., NRECA and TDU Systems. 

164E.g., Lassen and Public Power Council. 

ISOs and RTOs.159 PJM contends on 

reply that New York Commission’s 

proposal for coordination of ATC 

between ISOs and RTOs has been 

fulfilled at least between PJM and its 

neighbors, arguing that New York 

Commission’s proposal is unnecessary 

and would add a layer of bureaucracy 

and cost. TAPS expresses concern with 

the Commission proposal to use NERC 

and encourages the Commission to be 

precise in its direction to NERC to 

accomplish the needed objective. 

Commission Determination 

221. The Commission directs public 

utilities, working through NERC and 

NAESB, to modify the ATC-related 

reliability standards and business 

practices in accordance with specific 

direction provided in this Final Rule. As 

we explain above, the development of a 

more coherent and uniform 

determination of ATC across a region 

will help limit the potential for undue 

discrimination in the calculation of 

ATC. The Commission concludes that 

the NERC reliability standards 

development process and the NAESB 

business practices development process 

are the appropriate forums for 

developing this consistency. 

222. NERC has been certified as the 

ERO and, as such, has been found to 

have the ability to develop reliability 

standards through processes with 

reasonable notice and opportunity for 

public comment. NERC’s processes are 

open and provide due process as well as 

a balance of interests, while assuring 

independence from users and owners 

and operators of the bulk-power system. 

Moreover, NAESB has a long history of 

developing standard business practices 

for the electric industry, on which the 

Commission has relied in various 

contexts. While other entities may bring 

certain benefits, commenters have not 

demonstrated the superiority of IEEE, a 

regional reliability organization, or a 

particular RTO over NERC and NAESB. 

Once components of ATC are made 

consistent and ATC calculation 

methodologies are made transparent, 

opportunities for discretion that may 

lead to undue discrimination in the 

calculation of ATC will be sufficiently 

eliminated to invalidate the need for the 

creation of independent entities to 

oversee that calculation. To the extent 

that, even following the adoption of 

these reforms, customers have 

complaints regarding the calculations 

performed by individual transmission 

owners, they can be addressed on a 

case-by-case basis. 

223. With respect to a timeline for 

completion, the Commission concurs 

with NERC that a significant amount of 

work remains to be done on ATC-related 

reliability standards development. We 

also agree with the many commenters 

who state that the NOPR’s proposed sixmonth timeline is too short for such a 

complex assignment. Although NERC 

projects that it may be able to complete 

the process by the summer of 2007 

(which is approximately six months 

from the date of the Final Rule), we 

believe NERC should have additional 

flexibility with respect to its timeline. 

Accordingly, we direct public utilities, 

working through NERC, to modify the 

ATC-related reliability standards within 

270 days after the publication of the 

Final Rule in the Federal Register. We 

also direct public utilities to work 

through NAESB to develop business 

practices that complement NERC’s new 

reliability standards within 360 days 

after the publication of the Final Rule in 

the Federal Register. Finally, we direct 

NERC and NAESB to file, within 90 

days of publication of the Final Rule in 

the Federal Register, a joint status 

report on standards and business 

practices development and a work plan 

for completion of this task within the 

timeframe established above.160

c. Applicability to ISOs, RTOs, and 

Non-Public Utility Transmission 

Providers 

NOPR Proposal 

224. The Commission did not 

specifically address the application of 

the ATC-related reforms proposed in the 

NOPR to ISOs and RTOs or non-public 

utility transmission providers. 

Comments 

225. ISOs and RTOs believe that the 

Commission should not require 

wholesale revisions of RTO and ISO 

tariffs, even on such issues as ATC 

standards.161 They caution that many 

regional grid operators’ tariffs contain 

nonconforming provisions that were the 

product of extensive debate, litigation 

and settlements. In addition, some 

commenters point out that concern 

about ATC calculations is a non-issue in 

many ISO/RTO regions because 

transmission services in those regions 

are not based on physical transmission 

reservations.162

226. MISO argues that AFC 

calculation methodologies should be 

established via the RTO stakeholder 

process, not NERC. In its reply 

comments, Exelon expresses 

disagreement with MISO and states that 

there must be one standard for ATC 

calculations, not several methods based 

on the desires of different sets of 

stakeholders. Several commenters also 

believe that ISOs/RTOs should not be 

exempt from the requirements for 

consistent and transparent ATC 

calculations.163

227. EEI asks the Commission to 

require all municipal and other nonpublic utility transmission providers to 

adhere to any requirement for consistent 

and transparent ATC/AFC calculation. 

In its view, applying the ATC-related 

reforms to these nonjurisdictional 

entities would recognize the 

interconnected nature of the 

transmission grid. EEI argues that 

greater transparency and consistency in 

the provision of transmission service 

would be frustrated if all transmission 

providers do not have to comply. Other 

commenters reply that EEI’s concerns 

are unfounded and describe an example 

in the WECC region, where the 

methodologies and practices regarding 

ATC calculations are developed by 

representatives from all affected 

transmission providers, utilities, and 

market participants, including 

nonjurisdictional entities.164

228. LPPC contends that the NERC 

reliability standards related to ATC 

calculation will already be applicable to 

both public and non-public utilities. 

LPPC argues that NERC standards, when 

final, will be filed with the Commission, 

become part of the ERO’s mandatory 

reliability standards and will be fully 

applicable to otherwise 

nonjurisdictional entities. As a result, 

the ATC standards will be applicable to 

and enforceable upon all transmission 

owners, whether or not the transmission 

owner has an OATT. 

Commission Determination 

229. We discuss the applicability of 

the Final Rule to ISOs and RTOs in 

section IV.C.2 above. With respect to the 

application of the ATC requirements of 

this Final Rule to municipal and other 

non-public utility transmission 

providers, we likewise note that the 

applicability of the rule generally to 

such entities is addressed in section 


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165E.g., Chandley-Hogan, EPSA, PJM, San Diego 

G&E, and Transparent Dispatch Advocates Reply. 

166E.g., APPA, CMUA, CPA, Duke, EEI, Entergy, 

LPPC, Public Power Council, Sacramento, and 

WestConnect Reply. 

167E.g., MAPP and MidAmerican. 

168For example, WECC has a documented open 

process for establishing TTC for the Western 

Interconnection. 

IV.C.3. We note here, however, that 

such entities will be required to comply 

with reliability standards developed 

under FPA section 215. As LPPC 

acknowledges, once these reliability 

standards are approved they will 

become part of the ERO’s mandatory 

reliability standards and, thus, will be 

applicable to and enforceable upon all 

transmission owners, whether or not the 

transmission owner has adopted the 

OATT. 

d. Alternatives to ATC Consistency 

Comments 

230. Some commenters contend that 

the NOPR is focused too narrowly on 

simply improving the consistency and 

transparency of ATC determinations 

and suggest that a focus on balancing (or 

dispatch) services and how those are 

priced would allow the Commission to 

avoid the pitfalls inherent in the ATC 

approach.165 In their view, such an 

approach would eliminate much of the 

difference between how third parties are 

treated in RTO versus non-RTO systems. 

Constellation encourages the 

Commission to consider requiring 

transmission providers to implement 

all-inclusive, security constrained 

economic dispatch processes. In reply 

comments, Chandley-Hogan argue that 

the Commission’s ATC-related 

proposals in the NOPR confuse how 

transmission service is actually 

provided in most of the United States 

and, as a result, the Commission’s 

analysis of perceived problems in the 

calculation of ATC is flawed, 

inconsistent with network realities and 

the laws of physics, and incompatible 

with reliable operations. 

231. Contrary to the above claims, 

some commenters find that ATC 

provides a functionally useful measure 

of available capacity and has certain 

advantages over alternative models.166

These commenters argue that the factual 

record does not support conclusions 

that bid-based, marginal cost dispatch 

by a third party is inherently more 

efficient or inherently more likely to 

remedy undue-discrimination than the 

OATT model, and cannot overcome the 

considerable real world obstacles to 

pure economic redispatch, including 

overlapping and dynamic constraints, 

and the physical realities in the Western 

Interconnection that often limit the pool 

of resources that can be redispatched to 

solve constraints. LPPC contends that 

the principal advantage of ATC is the 

certainty that it provides for available 

capacity, suggesting that the contract 

path paradigm facilitates long-term 

bilateral contracting. 

Commission Determination 

232. In this rulemaking, the 

Commission is requiring consistency in 

the determination of ATC with the 

purpose of improving a customer’s 

ability to receive transmission service 

on a non-discriminatory basis. These 

reforms are fully consistent with 

operational reality, and we decline to 

mandate the security constrained 

economic dispatch alternative proposed 

by Chandley-Hogan. Chandley-Hogan 

argue that it would be unduly 

discriminatory to exclude third-party 

generators from an efficient dispatch to 

serve native load and therefore a 

centralized, bid-based market is 

required. We agree that a centralized 

bid-based market can benefit customers 

and, over a large region, can manage 

congestion efficiently. We do not 

believe, however, that mandating that 

result—essentially requiring that Day 2 

RTOs be adopted in every region of the 

country—is necessary to remedy undue 

discrimination in the provision of 

transmission service. The concern 

raised by Chandley-Hogan is not related 

solely to the nondiscriminatory use of 

the transmission system. It also 

implicates the purchase decisions of 

transmission providers on behalf of 

their native load customers. These 

decisions are regulated primarily by the 

states and we decline to take generic 

action in this rulemaking to reform the 

processes by which those purchases are 

made. 

e. ATC Components 

233. The next several sections address 

components of ATC that must be made 

consistent to remove the potential for 

undue discrimination, namely TTC/ 

TFC, ETC, CBM, and TRM. 

(1) Total Transfer Capability (TTC)/ 

Total Flowgate Capability (TFC) 

NOPR Proposal 

234. The Commission proposed to 

direct public utilities, working through 

NERC, to develop consistent practices 

for calculating total transfer/flowgate 

capability (TTC/TFC). Although the 

NERC reliability regions have 

historically calculated transfer 

capability using different approaches, 

the Commission expressed its view that 

guidelines for a common approach to 

calculating transfer capability are 

achievable. The Commission also stated 

that the criteria used for identifying 

flowgates and determining TFC could be 

more consistent. 

Comments 

235. Entergy supports the 

development of consistent practices for 

determining transfer capability while 

maintaining flexibility to recognize 

regional and system-specific differences. 

APPA agrees that the calculation of 

TTC/TFC is, for the most part, a regional 

calculation. APPA states that the 

Western Interconnection and ERCOT 

use their own methods, which are 

generally applied system-wide. APPA 

believes that more standardization and 

coordination of TTC/TFC among 

transmission providers in the Eastern 

Interconnection, where two primary 

methods are used to calculate TTC or 

TFC, would be desirable because of 

reported loop-flow problems in the 

Eastern Interconnection. 

236. In order to increase transfer 

capability from existing facilities, 

AWEA proposes that the Commission 

direct NERC, as part of developing 

consistent ATC standards, to investigate 

the impact of implementing dynamic 

line ratings in TTC/TFC calculations 

and propose protocols to effectuate such 

a program. In response to AWEA’s 

proposal, commenters state that if the 

Commission decides to provide 

guidance to NERC with regard to 

dynamic line ratings, the Commission 

should encourage NERC to develop 

standards with regard to dynamic line 

ratings in the operating horizon, but not 

in the planning horizon.167

Commission Determination 

237. The Commission adopts the 

NOPR proposal and directs public 

utilities, working through NERC, to 

develop consistent practices for 

calculating TTC/TFC. We direct public 

utilities, working through NERC, to 

address, through the reliability 

standards process, any differences in 

developing TTC/TFC for transmission 

provided under the pro forma OATT 

and for transfer capability for native 

load and reliability assessment studies. 

238. We acknowledge that reliability 

regions have historically calculated 

transfer capability using different 

approaches, and we agree that regional 

differences should be respected.168

However, as already discussed above 

regarding ATC, the TTC requirements 

will be determined by the NERC 

reliability standards and any request for 

a regional difference from the reliability 

standards must take place through the 

NERC process. 


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169The purpose of MOD–001 is to promote the 

consistent and uniform application of transfer 

capability calculations among the transmission 

system users. 

170By ‘‘appropriate,’’ we mean that reservations 

accounted for under ETC depend on the firmness 

and duration of the reservation. The specific 

characteristics should be developed in the 

reliability standard. 

171TRM also includes such things as loop flow 

and parallel path flow. 

239. With respect to AWEA’s proposal 

regarding implementing dynamic line 

ratings in TTC/TFC calculations, the 

Commission finds that this proposal is 

outside the scope of this rulemaking as 

it does not appear to relate to undue 

discrimination in transmission service 

and, in any event, would best be 

addressed in the first instance through 

the NERC reliability standards 

development process, addressing 

reliability standards that regulate 

facility ratings. If AWEA desires to 

pursue this proposal, it should propose 

an appropriate dynamic line rating 

standard within the ERO’s reliability 

standards development process. 

(2) Existing Transmission Commitments 

(ETC) 

NOPR Proposal 

240. In the NOPR, the Commission 

expressed its view that the lack of 

consistency in modeling of existing 

transmission commitments (ETC) 

resulted in excessive discretion in 

determining how much capacity a 

transmission provider sets aside for 

native load, including its network 

customers. The Commission therefore 

proposed the development of a 

consistent methodology for determining 

the capacity needed and set aside for 

native load usage. The Commission also 

proposed that accounting for 

transmission reservations in an ATC/ 

AFC calculation be more consistent. The 

Commission further proposed that 

public utilities, working through NERC, 

establish and specifically identify the 

reservations to be used in determining 

ETC. 

Comments 

241. Entegra and PGP support 

increasing consistency in determining 

ETC. APPA agrees that it would be 

helpful to standardize the method of 

accounting for ETC on an 

interconnection-wide basis. APPA 

states, however, that flexibility might be 

required among the interconnections. 

TDU Systems requests that the 

Commission define with specificity the 

types of transmission service requests or 

scheduled transmission transactions 

that should be included in ETC and 

agrees with the Commission that 

inclusion of all requests for 

transmission service in ETC is likely to 

overstate usage of the system, thus 

understating ATC. It suggests that the 

Commission develop a bright line 

method for calculating ETC. NERC notes 

that its proposed reliability standards 

would define ETC and require 

appropriate documentation. NERC adds, 

however, that the components included 

in ETC appear to be candidates for 

business practices rather than reliability 

standards. 

242. Williams proposes that ETC be 

the subject of an expanded definition 

and that native load growth projections 

be based on verifiable data provided by 

an independent source. It also states 

that transmission providers should be 

required to update ATC based on each 

confirmed transmission service 

reservation (point-to-point or network, 

firm or non-firm). 

Commission Determination 

243. To achieve greater consistency in 

ETC calculations and further reduce the 

potential for undue discrimination, the 

Commission adopts the NOPR proposal 

and directs public utilities, working 

through NERC and NAESB, to develop 

a consistent approach for determining 

the amount of transfer capability a 

transmission provider may set aside for 

its native load and other committed 

uses. We expect that NERC will address 

ETC through the MOD–001 reliability 

standard rather than through a separate 

reliability standard.169 By using MOD–

001, the ETC calculation can be adjusted 

to be applicable to each of the three 

ATC methodologies under development 

by NERC. 

244. In order to provide specific 

direction to public utilities and NERC, 

we determine that ETC should be 

defined to include committed uses of 

the transmission system, including (1) 

Native load commitments (including 

network service), (2) grandfathered 

transmission rights, (3) appropriate 

point-to-point reservations,170 (4) 

rollover rights associated with long-term 

firm service, and (5) other uses 

identified through the NERC process. 

ETC should not be used to set aside 

transfer capability for any type of 

planning or contingency reserve, which 

are to be addressed through CBM and 

TRM.171 In addition, in the short-term 

ATC calculation, all reserved but 

unused transfer capability (nonscheduled) shall be released as non-firm 

ATC. 

245. We agree with TDU Systems that 

inclusion of all requests for 

transmission service in ETC would 

likely overstate usage of the system and 

understate ATC. We therefore find that 

reservations that have the same point of 

receipt (POR) (generator) but different 

point of delivery (POD) (load), for the 

same time frame, should not be modeled 

in the ETC calculation simultaneously if 

their combined reserved transmission 

capacity exceeds the generator’s 

nameplate capacity at POR. This will 

prevent overly unrealistic utilization of 

transmission capacity associated with 

power output from a generator 

identified as a POR. We direct public 

utilities, working through NERC, to 

develop requirements in MOD–001 that 

lay out clear instructions on how these 

reservations should be accounted. One 

approach that could be used is 

examining historical patterns of actual 

reservation use during a particular 

season, month, or time of day. 

246. We agree with NERC that some 

elements of ETC are candidates for 

business practices rather than reliability 

standards. Accordingly, we direct 

public utilities, working through 

NAESB, to develop business practices 

necessary for full implementation of the 

developed MOD–001 reliability 

standard. 

247. We decline to adopt Williams’s 

proposal to require that native load 

growth be based on the verifiable data 

provided by an independent source. 

Through increased consistency and 

transparency of ATC determinations, 

including requirements for posting 

additional data, third parties will be 

able to verify the accuracy of ETC, 

helping to eliminate opportunities for 

undue discrimination. 

(3) Capacity Benefit Margin (CBM) 

NOPR Proposal 

248. In the NOPR, the Commission 

proposed three options to address the 

CBM component of ATC: (1) Have NERC 

develop clear standards for how the 

CBM value should be determined, 

allocated across transmission paths, and 

used; (2) charge an entity for which 

transfer capability has been set aside to 

meet generation reliability criteria a 

separate rate for this service; or (3) 

eliminate CBM and require an entity 

reserving ATC to meet generation 

reserve (currently through CBM) to 

designate network resources on the 

other side of the interface and make an 

associated transmission service 

reservation. 

Comments 

249. Numerous commenters support 

the Commission’s proposed option one, 

requiring NERC to develop clear 

standards for how the CBM value 

should be determined, allocated across 


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172E.g., Allegheny, Ameren, EEI, Duke, NRECA, 

TVA, APPA, Bonneville, EPSA, FirstEnergy, 

Indianapolis Power, MidAmerican, Pinnacle, PJM, 

PGP, PNM–TNMP, Public Power Council, 

Sacramento, Seattle, South Carolina E&G, TANC, 

TDU Systems, and Wisconsin Electric. 

transmission paths, and used.172 They 

believe that CBM ensures the ability to 

import needed power to support system 

conditions. TVA argues that option two 

would be costly and may cause some 

systems to forego CBM, thereby 

jeopardizing service to native load 

customers. PJM states that option two is 

irrelevant in PJM since PJM ‘‘totals’’

reservations and decides when CBM can 

be used. Supporters of option one 

criticize option three, elimination of 

CBM, as costly and a threat to 

transmission system reliability. 

Southern, Progress Energy, and PJM 

emphasize that, without CBM, the LSEs 

would need to increase their reserve 

margin by contracting for additional 

generation capacity, costing millions of 

dollars. In addition, Ameren and TVA 

believe that CBM elimination will 

increase the likelihood of widespread 

blackouts in emergency conditions. 

250. At the October 12 Technical 

Conference, Exelon supported option 

two proposing a charge for CBM. Exelon 

contended that, in a rate-making 

context, there would be an increase in 

the divisor of the rate by the amount of 

CBM set-aside which would lower the 

point-to-point charge. Consequently, 

those not benefiting from the CBM setaside effectively would be paying a 

lower charge. 

251. Constellation and Morgan 

Stanley support the elimination of CBM 

and argue that CBM and TRM are often 

used interchangeably and result in 

duplicative transmission set-asides. 

They also argue that there is no 

compelling need for CBM in the current 

liquid market environment. In addition, 

Morgan Stanley states that LSEs 

affiliated with the transmission provider 

should not be allowed to use CBM for 

long-term planning purposes as an 

excuse to avoid undertaking needed 

resource additions or to conceal the true 

cost of their load serving functions. 

Furthermore, the Commission should 

not be distracted by assertions that such 

long-term arrangements are necessary 

for ‘‘reliability,’’ when in fact they are 

simply a way to protect the economic 

interests of a particular entity. 

252. Duke replies that Constellation 

mistakenly believes that CBM is 

currently only available to a 

transmission provider’s native load 

when, in fact, for those transmission 

providers that establish CBM, it should 

be established for the load of all LSEs 

in the control area. Duke contends that 

not all transmission providers set aside 

capacity through CBM for their native 

load; to the extent that a transmission 

provider does not set aside CBM, there 

should be no obligation to allow other 

LSEs to do so. Duke proposes that the 

Commission should continue to permit 

such flexibility. 

253. NERC takes no position on CBM, 

expecting that the issue can be settled 

through the NERC and NAESB 

Procedure for Joint Standards 

Development and Coordination and 

through other open forums. 

254. TAPS suggests that the 

Commission ensure that all LSEs have 

both access to CBM to meet their 

reserve-sharing needs and meaningful 

input into how much CBM is reserved. 

To do so, TAPS recommends the 

creation of a reserve-sharing group made 

up of the transmission provider and 

LSEs it serves. It argues that this would 

remove reservation decisions from the 

sole discretion of the verticallyintegrated transmission provider and 

instead have them made by the 

transmission provider/LSE reservesharing group, subject to dispute 

resolution at the Commission. All LSEs 

would be invited to participate in the 

studies as well as review the results and 

assumptions. Moreover, once a regional 

planning process is established, as 

proposed in the NOPR, TAPS 

recommends that the regional planning 

group be required to approve the CBM 

reservation as well. 

255. Williams suggests that a 

transmission provider must designate 

network resources and reserve firm 

transfer capability on both sides of the 

control area transmission interface in 

order to reserve CBM. Duke replies that, 

although some commenters prefer 

eliminating CBM and replacing it with 

additional designated network 

resources, CBM is the preferable option 

because it is less costly. Duke further 

argues that the choice is between setting 

aside both additional transmission and 

generation capacity to deal with 

emergencies (the additional designated 

network resource approach) versus 

setting aside only transmission (the 

CBM approach). Having to procure 

additional designated network resources 

to keep in reserve reduces one of the 

main benefits of interconnected 

operations. Duke argues that eliminating 

CBM would drive up costs for network 

customers, as they would have to 

procure additional generation and 

transmission resources. EEI adds that 

such a proposal may result in increased 

LSE reserve requirements, over-building 

of generation supply, and a reduction, 

rather than an increase, in ATC. 

Commission Determination 

256. The Commission concludes that 

it is appropriate to allow LSEs to retain 

the option of setting aside transfer 

capability in the form of CBM to 

maintain their generation reliability 

requirement. We agree with commenters 

that, without CBM, LSEs would have to 

increase their generation reserve 

margins by contracting for generation 

capacity, which may result in higher 

costs without additional reliability 

benefits. We require, however, the 

development of standards for how CBM 

is determined, allocated across 

transmission paths, and used in order to 

limit misuse of transfer capability set 

aside as CBM. Transmission providers 

also must reflect the set-aside of transfer 

capability as CBM in the development 

of the rate for point-to-point 

transmission service to ensure 

comparable treatment for point-to-point 

to customers. 

257. The Commission therefore 

adopts a combination of the NOPR 

options one and two, and declines to 

adopt option three. First, we require 

public utilities, working through NERC 

and NAESB, to develop clear standards 

for how the CBM value shall be 

determined, allocated across 

transmission paths, and used. We 

understand that NERC has already 

begun the process of modifying several 

of the CBM-related reliability standards 

and that the drafting process is a joint 

project with NAESB. Second, we require 

transmission providers to reflect the setaside of transfer capability as CBM in 

the development of the rate for point-topoint transmission service. 

258. We note that there is broad 

concern that eliminating CBM (option 

three) would impose extraordinary costs 

for meeting generation reliability 

criteria, which then may lead utilities to 

reduce their generation reliability 

requirement to avoid the cost increase. 

We believe that the reforms reflected in 

combining options one and two are 

sufficient to remedy undue 

discrimination and that the adverse 

effects associated with option three are 

neither warranted nor required. We 

reject Morgan Stanley’s call for CBM 

elimination on the grounds that CBM is 

acting as a disincentive to undertake 

needed generation resource additions. It 

would be inappropriate for the 

Commission to restrict the ability of an 

LSE to determine how best to meet its 

generation reliability criteria. 

259. To ensure CBM is used for its 

intended purpose, CBM shall only be 

used to allow an LSE to meet its 

generation reliability criteria. Consistent 

with Duke’s statement, we clarify that 


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173The MOD–008 and MOD–009 reliability 

standards document regional TRM methodologies 

and procedures for verifying TRM values. 

174E.g., Allegheny, APPA, EEI, EPSA, Exelon, 

LPPC, MidAmerican, NRECA, Northwest IOUs, 

NorthWestern, Occidental, Pinnacle, Powerex, 

PNM–TNMP, PPL, PJM, PPM, and WestConnect. 

175Exelon recommends that the following factors 

should be the same for the planning process and 

ATC/AFC process to achieve consistency: base case 

flows, reservation impacts, TRM and CBM 

forecasted to occur simultaneously; counterflows; 

positive impacts resulting from reservations and 

generation dispatch; TRM for the same scenarios; 

and CBM. 

176Citing WECC Rocky Mountain Operating and 

Planning Group, Determination of Available 

Transfer Capability within the Western 

Interconnection, June 2001, page 9, http:// 

www.wecc.biz/modules.php?op=modload&name=

Downloads&file=index&req=getit&lid=1035. 

each LSE within a transmission 

provider’s control area has the right to 

request the transmission provider to set 

aside transfer capability as CBM for the 

LSE to meet its historical, State, RTO, or 

regional generation reliability criteria 

requirement such as reserve margin, loss 

of load probability (LOLP), the loss of 

largest units, etc. 

260. We direct public utilities, 

working through NERC, to develop clear 

requirements for allocating CBM over 

transmission paths and flowgates. While 

we do not mandate a particular 

methodology for allocating CBM to 

paths and flowgates, one approach 

could be based on the location of the 

outside resources or spot market hubs 

that an LSE has historically relied on 

during emergencies resulting from an 

energy deficiency. 

261. We concur with TAPS’ proposal 

that all LSEs should have access to CBM 

and meaningful input into how much 

transfer capability is set aside as CBM. 

In the transparency section below, we 

provide detailed requirements regarding 

availability of documentation used to 

determine the amount of transfer 

capability to be set aside as CBM and 

the posting of CBM values and 

narratives. Access to this documentation 

will enable LSEs to validate how much 

transfer capability is set aside as CBM 

on each system and provide them with 

information to question whether the setaside is consistent with the reliability 

standards and this Final Rule. 

262. Concerning TAPS’ proposal to 

remove the reservation decision from 

the sole discretion of transmission 

providers, we determine that LSEs 

should be permitted to call for use of 

CBM, if they do so pursuant to 

conditions established in the reliability 

standards development process. We 

direct public utilities working through 

NERC to modify the CBM-related 

standards to specify the generation 

deficiency conditions during which an 

LSE will be allowed to use the transfer 

capability reserved as CBM. In addition, 

we direct that transmission set aside as 

CBM shall be zero in non-firm ATC 

calculations. Finally, we order public 

utilities to work with NAESB to develop 

an OASIS mechanism that will allow for 

auditing of CBM usage. 

263. We also require transmission 

providers to design their transmission 

charges to ensure that the class of 

customers not benefiting from the CBM 

set-aside, i.e., point-to-point customers, 

do not pay a transmission charge that 

includes the cost of the CBM set-aside. 

To do this, transmission providers are 

required to submit redesigned 

transmission charges that reflect the 

CBM set-aside through a limited issue 

FPA section 205 rate filing as part of its 

initial ATC-related compliance filing. 

These filings, which may be submitted 

within 120 days after the publication of 

the Final Rule in the Federal Register, 

may be limited to the rate design change 

only, i.e., they will not require the 

submission of cost of service data or a 

revision to the transmission provider’s 

revenue requirement. 

264. With respect to TAPS’ proposal 

that all LSEs should be allowed to use 

CBM to meet their reserve-sharing 

needs, we believe that TRM is the 

appropriate category for that purpose, 

not CBM. We reject TAPS’ proposal to 

use CBM for the LSE’s reserve-sharing 

needs, but instead make TRM available 

for the incremental power flows 

resulting from reserve sharing, as 

explained next. 

265. As we are rejecting option three, 

which would have required the 

reservation of transfer capability rather 

than using CBM, we also reject 

Williams’ proposal to require the 

reservation of transfer capability on both 

sides of an interface for CBM. 

(4) Transmission Reserve Margin (TRM) 

NOPR Proposal 

266. Finally, the Commission 

proposed the development of reliability 

standards MOD–008 and MOD–

009 173that specify the uncertainties that 

TRM could be used to accommodate, 

which could include (1) Load forecast 

and load distribution error, (2) 

variations in facility loadings, (3) 

uncertainty in transmission system 

topology, (4) loop flow impact, (5) 

variations in generation dispatch, 

including intermittent resources, (6) 

automatic sharing of reserves, and (7) 

other uncertainties identified through 

the NERC reliability standards 

development process. 

Comments 

267. Most commenters agree that the 

existing definitions for TRM require 

clarification.174 Commenters also agree 

that NERC should be required to 

develop clear standards for the 

determination of TRM, including 

specifying the criteria used in the 

determination of TRM.175 PNM–TNMP 

supports the Commission’s proposal, 

pointing out that the implementation of 

the current NERC standards definition 

for TRM and CBM could result in its 

double-counting, which must be 

eliminated. APPA members in the 

Western Interconnection suggest that 

regional variations be permitted. They 

also note that the modeling methods 

used by WECC and its sub-regions may 

differ from those used in the Eastern 

Interconnection. For example, they 

contend that uncertainties associated 

with transmission maintenance 

schedules that are driven by hydroproduction curves will seasonally affect 

TRM set-asides on certain transfer 

paths. PJM believes that the TRM 

methodology should be consistent at the 

regional reliability organization level. 

PJM also contends that TRM should be 

coordinated, exchanged and respected 

on external flowgates and that the 

concept of a maximum TRM, by 

percentage, should be adopted in the 

NERC standards. 

268. Consistent with its position on 

CBM, TAPS proposes that TRM setasides should be conditioned on 

inclusive reserve-sharing arrangements, 

with the reservations determined by the 

reserve-sharing group, subject to dispute 

resolution before the Commission (and, 

eventually, approval by joint planning 

groups). 

269. PNM–TNMP suggests that the 

Commission consider definitions to 

include the following clarification taken 

from WECC procedures on ATC: ‘‘If the 

limitation on the use of TRM to 59 

minutes would force a Transmission 

Provider to set aside unnecessary CBM 

on the same path as the TRM, that 

Transmission Provider may utilize the 

TRM beyond the 59 minutes.’’ 176 PNM–

TNMP states that this would allow the 

transmission provider to maximize the 

ATC by not needlessly setting aside 

twice the amount of transmission (TRM 

and CBM) than is necessary for 

reliability. 

270. Nevada Companies argue that no 

new standards are required for TRM and 

that any further action would be 

burdensome. They explain that NERC 

has a well-established definition that 

does not require further clarification. In 

their view, all that is required is a 

complete statement, to be posted on 

OASIS, regarding the transmission 

provider’s application of TRM. NERC 


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177The agreement may appropriately restrict the 

sharing of sensitive information with customer 

personnel that are involved only in transmission 

functions, as opposed to merchant functions. 

178The Commission noted that this would 

include review of load flow base cases, short circuit 

data, transient and dynamic stability simulation 

data, contingency (files should contain information 

on special protection schemes and remedial action 

plans) subsystem and monitoring files, and 

production cost models. 

comments that the existing reliability 

standards for TRM will be revised to 

require clear documentation of the 

calculation of TRM. It also adds that the 

revised standard will make various TRM 

components mandatory to achieve more 

consistency across methodologies. 

271. Santee Cooper urges the 

Commission to ensure that service to 

native load and transmission system 

reliability will not be compromised as 

the Commission seeks greater levels of 

consistency in the calculation of ATC. It 

states that the Commission also must be 

cognizant of the importance of TRM in 

the provision of service to native load. 

Commission Determination 

272. The Commission adopts the 

NOPR proposal and requires public 

utilities, working through NERC, to 

complete the ongoing process of 

modifying TRM standards MOD–008 

and MOD–009. We understand that the 

standard drafting process is underway 

as a joint project with NAESB. 

273. The Commission also adopts the 

NOPR proposal to establish standards 

specifying the appropriate uses of TRM 

to guide NERC and NAESB in the 

drafting process. Transmission 

providers may set aside TRM for (1) 

Load forecast and load distribution 

error, (2) variations in facility loadings, 

(3) uncertainty in transmission system 

topology, (4) loop flow impact, (5) 

variations in generation dispatch, (6) 

automatic sharing of reserves, and (7) 

other uncertainties as identified through 

the NERC reliability standards 

development process. Because load, 

facility loading and other uncertainties 

constantly deviate, we will not require 

that TRM set aside capacity be set at 

zero in the non-firm ATC calculation. In 

other words, we will not require transfer 

capability that is set aside as TRM to be 

sold on a non-firm basis. We find that 

clear specification in this Final Rule of 

the permitted purposes for which 

entities may reserve CBM and TRM will 

virtually eliminate double-counting of 

TRM and CBM. 

274. We will not adopt PNM-TNMP’s 

proposal regarding use of set aside 

transfer capability as TRM beyond 59 

minutes, rather than converting it to 

CBM. Our proposal is to separate 

transfer capability set asides as either 

CBM or TRM without regard to duration 

of use of the set aside. Therefore, such 

a clarification is not necessary. 

275. In addition, we direct public 

utilities, working through NERC, to 

establish an appropriate maximum 

TRM. One acceptable method may be to 

use a percentage of ratings reduction, 

i.e., model the system assuming all 

facility ratings are reduced by a specific 

percentage. This is a relatively simple 

method and, if adopted as the reliability 

standard’s method, should not restrict a 

transmission provider from using a 

more sophisticated method that may 

allow for greater ATC without reducing 

overall reliability. 

276. Because of the operational 

characteristics of the uncertainties that 

are to be accommodated using TRM, 

and their aggregate impact on reliable 

operation, we require each transmission 

provider to calculate, and allocate on 

the paths and flowgates, the aggregate 

TRM value for all LSEs within its area. 

We support NERC’s plan to revise 

existing reliability standards for TRM to 

require clear documentation of the TRM 

calculation, as we expect the TRM value 

to be supported and fully transparent. In 

addition, we require each transmission 

provider to make available all 

underlying documentation, including 

work papers and load flow base cases, 

used to determine TRM, to any 

transmission customer and LSE within 

its control area, subject to a 

confidentiality agreement,177 if 

necessary. We agree with Santee 

Cooper’s comments that the 

Commission must ensure that service to 

native load and system reliability are 

not compromised. We believe that our 

requirement for public utilities to work 

through NERC satisfies such concerns. 

277. With respect to the proposal to 

permit regional variations in the TRM 

calculation methodology, we reiterate 

our position stated above that any 

request for regional difference from the 

applicable reliability standards must 

take place through the NERC reliability 

standards development process. With 

respect to TAPS’ proposal regarding 

reserve sharing groups, we clarify that, 

to the extent transfer capability is 

needed for transmission of shared 

reserves, this is included under TRM. 

However, as noted previously in the 

CBM discussion, we are not mandating 

the use of reserve sharing groups. 

f. Modeling, Assumptions and Input 

Data 

NOPR Proposal 

278. The Commission’s proposal with 

regard to modeling, assumptions and 

data inputs was based on a principle 

that there should be consistency among 

transmission providers and between 

what the transmission provider does for 

its operation and expansion planning 

for native load and what it does in 

determining short and long-term ATC 

for all uses. The Commission stated its 

view that consistency is necessary to 

ensure non-discriminatory treatment by 

eliminating a transmission provider’s 

ability to use discretion to the 

disadvantage of competitors. The 

Commission proposed three specific 

areas for reform. 

279. First, the Commission proposed 

to require public utilities, working 

through NERC, to modify the ATCrelated standards to incorporate a 

requirement for periodic validation and 

modification of models to ensure that 

they are up to date.178 The Commission 

stated that the models should be 

updated and benchmarked to actual 

events. 

280. Second, the Commission 

proposed that, to the maximum extent 

practicable, the same data must be used 

by the transmission provider to 

determine short- and long-term ATC as 

those used in system operation and 

planning studies, respectively. 

281. Third, the Commission proposed 

that public utilities, working through 

NERC, develop assumptions for use in 

ATC determinations and that the 

assumptions remain consistent among 

transmission providers to the maximum 

extent practicable. The Commission 

indicated that short- and long-term ATC 

calculations should be developed using 

consistent assumptions regarding 

representative load levels, generation 

dispatch, transmission reservations and 

counterflows, in addition to any other 

modeling assumptions identified by 

NERC. The Commission further 

proposed that there should be a 

consistent approach to the modeling of 

load levels, a method established for 

determining which generators should be 

modeled in service (including guidance 

on how independent generators should 

be considered), consistency in the 

simulation of power flows from points 

of receipt to delivery when sources are 

unknown, and consistency in the 

manner in which ATC/AFC reservations 

are accounted for. The Commission 

stated that the model for long-term ATC 

should include, to the maximum extent 

practicable, the same assumptions 

regarding new transmission and 

generation facilities additions and 

retirements as those used in planning 

for expansion. 

282. The Commission noted that the 

proposal is not intended to change the 

manner in which native load is served 


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179E.g., APPA, Arkansas Commission, 

Constellation, Entegra, Exelon, EPSA, ISO/RTO 

Council, LDWP, MidAmerican, Municipals, 

NRECA, CREPC, Sacramento, Santee Cooper, Suez 

Energy NA, TAPS, TDU Systems, WestConnect, and 

Williams. 

180E.g., Bonneville. Santee Cooper, and Entergy. 

181E.g., PJM, EPSA, and Ameren. 

182E.g., Sacramento, Manitoba Hydro, Nevada 

Companies, and TANC. 

183E.g., Sacramento. 

184The MOD–010 through MOD–025 reliability 

standards establish data requirements, reporting 

procedures, and system model development and 

validation for use in the reliability analysis of the 

interconnected transmission systems. 

185 Final Report on the August 14, 2003 Blackout 

in the United States and Canada: Causes and 

Recommendations. 

and sought comment on whether (and, 

if so, how) this proposal would affect 

service to native load customers. 

Comments 

283. Commenters generally discuss 

consistency of data, assumptions and 

modeling together so we in turn do the 

same. Many commenters support the 

proposals for consistency in data, 

assumptions and/or modeling.179 Others 

support flexibility or regional 

variation.180 A few commenters oppose 

specific aspects of the overall 

proposal.181

284. TDU Systems and Sacramento 

express support for the Commission’s 

proposal to require public utilities, 

working through NERC, to develop 

modeling assumptions for use in 

calculating ATC that are consistent with 

those used to plan the operation and 

expansion of the transmission system. 

Xcel, however, would have the 

Commission go further. Xcel 

recommends that the Commission 

enhance its proposal by establishing a 

date certain for transmission providers 

in the Western Interconnection to be 

required to account for impacts of loop 

flows when processing transmission 

service requests and calculating ATC. 

Xcel suggests that NERC be directed to 

develop standards for evaluation of 

counterflows on ATC. EPSA offers 

examples of specific data inputs that, in 

its view, should also be standardized 

among all transmission providers, 

which include: Load levels and 

distribution studies; transmission 

outages; generation outages; and 

generation dispatch. Ameren submits 

that any modeling of base generation 

dispatch must model generators, 

including merchant generators, as they 

are expected to run. 

285. Williams asks the Commission to 

require consistency between 

transmission planning horizon and 

procurement terms, and transparency 

around the long-term transmission 

planning assumptions. Williams states 

that third-party bids to a request for 

proposals are evaluated with 

transmission costs that may already be 

included in long-term transmission 

plans. Thus, argues Williams, 

procurement and long-term planning 

assumptions are intertwined. In reply, 

Entergy acknowledges and agrees that 

the models used for planning, 

operations and service request 

evaluations should generally be based 

on similar data and procedures, but 

argues that due to changes in system 

configuration, facilities included in 

transmission plans are often not needed 

at all and thus are not constructed. 

Therefore, Entergy proposes that the 

Commission allow NERC to determine 

the circumstances under which 

differences between models would be 

appropriate. 

286. Southern asks for clarification on 

what the Commission intends by 

proposing that modeling assumptions be 

consistent in the context of TTC 

assessments. Southern explains that, as 

the Commission has recognized, the 

inevitable changes in system conditions 

between different time horizons (e.g., 

real-time and planning and operations) 

would render this approach unreliable 

because load levels, dispatch 

arrangements, reservations, and outages 

cannot be the same over significantly 

different time horizons. 

287. Supporting regional differences, 

Bonneville contends that calculating 

ATC for a hydroelectric system requires 

different inputs and modeling 

assumptions than are appropriate for 

thermal-based systems. Bonneville 

explains that non-power constraints 

placed on hydroelectric projects that 

were built for multiple uses are a major 

concern on the Bonneville system. 

Consequently, hydro operators are more 

limited in their ability to use generation 

redispatch as a tool to meet long-term 

firm load obligations. Similarly, Santee 

Cooper cautions that overstandardization may result in certain 

parameters being misstated or 

inappropriately constrained, resulting in 

inaccurate reservations of capacity for 

native load purposes and a potentially 

detrimental effect on the reliability of 

service. It recommends that the 

Commission direct NERC to allow 

deviations from the standard modeling 

assumptions where the need can be 

supported, with the caveat that a 

utility’s modeling assumptions must be 

transparent and available for scrutiny. 

Seattle contends that modeling 

assumptions should be developed at the 

sub-regional level, consistent among 

adjacent transmission providers. TVA 

suggests that the transmission providers 

be allowed to retain flexibility to 

conduct risk analyses and reflect those 

in their modeling assumptions. 

288. Other commenters argue that 

modeling assumption standardization 

should not be performed by NERC and, 

instead, should be delegated to the 

regional reliability organizations or 

RTOs, as they possess a superior 

knowledge of the physical grid within 

their boundaries.182 PJM states that such 

issues are best left to the joint 

stakeholder processes and the resulting 

joint and common market initiatives. 

289. In response to the Commission’s 

inquiry as to how standardizing the 

modeling assumptions and data would 

affect native load, commenters generally 

state that standardization of ATC 

modeling assumptions would increase 

comparability of service to LSEs and 

enhance the ATC methodology and its 

nondiscriminatory application to grid 

utilization.183

Commission Determination 

290. The Commission directs public 

utilities, working through NERC, to 

modify the reliability standards MOD–

010 through MOD–025 184 to incorporate 

a requirement for the periodic review 

and modification of models for (1) Load 

flow base cases with contingency, 

subsystem, and monitoring files, (2) 

short circuit data, and (3) transient and 

dynamic stability simulation data, in 

order to ensure that they are up to date. 

This means that the models should be 

updated and benchmarked to actual 

events. We find that this requirement is 

essential in order to have an accurate 

simulation of the performance of the 

grid and from which to comparably 

calculate ATC, therefore increasing 

transparency and decreasing the 

potential for undue discrimination by 

transmission providers. 

291. We note that commenters 

generally were very supportive of the 

Commission’s proposals for review and 

update of models and for consistency of 

assumptions and data inputs. We 

received no adverse comments 

concerning our general proposal to 

require public utilities, working through 

NERC, to modify the ATC-related 

standards to incorporate a requirement 

for the periodic review and modification 

of models to ensure that they are up to 

date. Moreover, the need to improve the 

quality of system modeling was one of 

the U.S.-Canada Power System Task 

Force recommendations.185

292. The Commission also adopts the 

NOPR proposal to require transmission 

providers to use data and modeling 

assumptions for the short- and longterm ATC calculations that are 

consistent with that used for the 


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planning of operations and system 

expansion, respectively, to the 

maximum extent practicable. This 

includes, for example: (1) Load levels, 

(2) generation dispatch, (3) transmission 

and generation facilities maintenance 

schedules, (4) contingency outages, (5) 

topology, (6) transmission reservations, 

(7) assumptions regarding transmission 

and generation facilities additions and 

retirements, and (8) counterflows. We 

find that requiring consistency in the 

data and modeling assumptions used for 

ATC calculations will remedy the 

potential for undue discrimination by 

eliminating discretion and ensuring 

comparability in the manner in which a 

transmission provider operates and 

plans its system to serve native load and 

the manner in which it calculates ATC 

for service to third parties. The 

Commission directs public utilities, 

working through NERC, to modify ATC 

standards to achieve this consistency. 

293. With regard to EPSA’s request for 

the standardization of additional data 

inputs, we believe they are already 

captured in the Commission’s proposal 

as adopted in this Final Rule. Xcel asks 

the Commission to require consistency 

in the determination of counterflows in 

the calculation of ATC. Counterflows 

are included in the list of assumptions 

that public utilities, working through 

NERC, are required to make consistent. 

We believe that counterflows, if treated 

inconsistently, can adversely affect 

reliability and competition, depending 

on how they are accounted for. 

Accordingly, we reiterate that public 

utilities, working through NERC and 

NAESB, are directed to develop an 

approach for accounting for 

counterflows, in the relevant ATC 

standards and business practices. We 

find unnecessary Xcel’s request that we 

require a date certain for specific issues 

in the Western Interconnection to be 

addressed. Above we require public 

utilities, working through NERC, to 

modify the ATC standards within 270 

days after the publication of the Final 

Rule in the Federal Register. 

294. With regard to Williams’ request 

that the Commission require 

consistency between transmission 

planning horizons and procurement 

terms, we believe that such an express 

requirement is neither appropriate nor 

necessary. The manner in which 

transmission providers procure power 

for native load customers is generally 

outside the scope of this rulemaking. 

This notwithstanding, we note that by 

this Final Rule, Williams and other 

affected market participants will have 

an opportunity to participate in a 

transmission provider’s coordinated, 

regional planning process. This will 

provide a vehicle for interested parties 

to gain access to planning-related 

information and to have their own plans 

for transmission evaluated at the same 

time the transmission provider plans for 

its needs. Coupled with the 

modifications to the ATC-related 

reliability standards that require the 

same data and assumptions to be used 

for calculating long-term ATC as in 

system planning, these reforms are 

adequate to address Williams’ concern. 

To the extent there are changes on the 

system, these should be captured in the 

regional transmission planning process 

and in the determination of ATC. We 

therefore reject Entergy’s proposal to 

allow NERC to determine the 

circumstances under which differences 

between models would be appropriate 

in order to ensure comparable service 

for all transmission customers. 

295. We offer the following 

clarifications. In response to Southern, 

we clarify that we require consistent use 

of assumptions underlying operational 

planning for short-term ATC and 

expansion planning for long-term ATC 

calculation. We also clarify that there 

must be a consistent basis or approach 

to determining load levels. For example, 

one approach may be for transmission 

providers to calculate load levels using 

an on- and off-peak model for each 

month when evaluating yearly service 

requests and calculating yearly ATC. 

The same (peak- and off-peak) or 

alternative approaches may be used for 

monthly, weekly, daily and hourly ATC 

calculations. Regardless of the ultimate 

choice of approach, it is imperative that 

all transmission providers use the same 

approach to modeling load levels to 

enable the meaningful exchange of data 

among transmission providers. 

Accordingly, we direct public utilities, 

working through NERC, to develop 

consistent requirements for modeling 

load levels in MOD–001 for the services 

offered under the pro forma OATT. 

296. With respect to modeling of 

generation dispatch, we direct public 

utilities, working through NERC, to 

develop requirements in NERC’s MOD–

001 reliability standard specifying how 

transmission providers shall determine 

which generators should be modeled in 

service, including guidance on how 

independent generation should be 

considered. We agree with Ameren that 

any modeling of base generation 

dispatch must model generators, 

including merchant generators, as they 

are expected to run. Accordingly, we 

direct public utilities, working through 

NERC, to revise reliability standard 

MOD–001 by specifying that base 

generation dispatch will model (1) All 

designated network resources and other 

resources that are committed or have the 

legal obligation to run, as they are 

expected to run and (2) uncommitted 

resources that are deliverable within the 

control area, economically dispatched 

as necessary to meet balancing 

requirements. 

297. Regarding transmission 

reservations modeling, we direct public 

utilities, working through NERC, to 

develop requirements in reliability 

standard MOD–001 that specify (1) A 

consistent approach on how to simulate 

reservations from points of receipt to 

points of delivery when sources and 

sinks are unknown and (2) how to 

model existing reservations. 

298. In response to commenter 

requests in favor of flexibility and 

regional differences, we again require 

that any waivers from the approved 

NERC reliability standards must take 

place through the NERC reliability 

standards process as a request for 

regional difference. Also, we disagree 

with commenters who argue that 

modeling assumptions should be 

delegated to regional reliability 

organizations. The goal of this 

rulemaking is to increase consistency in 

ATC calculations and that is best 

accomplished through NERC, which has 

established processes to address 

requests for regional differences from 

the reliability standard requirements. 

We conclude that the NERC process is 

appropriate as it is open to all industry 

participants and, therefore, is a suitable 

arena for establishment of common 

standards for modeling assumptions. 

g. ATC Calculation Frequency 

NOPR Proposal 

299. The Commission proposed the 

development of standards requiring that 

the ATC calculation be performed with 

consistent frequency among 

transmission providers. Specifically, the 

Commission proposed that transmitting 

public utilities, working through NERC 

and NAESB, develop standards 

requiring that the calculation be 

performed by all transmission providers 

on a consistent time interval and in a 

manner that closely reflects the actual 

topology of the system, e.g., generation 

and transmission outages, load forecast, 

interchange schedules, transmission 

reservations, facility ratings, and other 

necessary data. The Commission also 

supported uniform updating of ATC 

values and its components (e.g., TTC, 

ETC, CBM, and TRM). 

Comments 

300. Alcoa and Powerex emphasize 

the critical need for ATC to be 

calculated more frequently for 


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186E.g., Allegheny, Ameren, Arkansas Municipal, 

Bonneville, Constellation, CAISO, Entergy, Exelon, 

FirstEnergy, LPPC, MidAmerican, Santee Cooper, 

Seattle, and TAPS. 

187Under the PJM/MISO Joint Operating 

Agreement (JOA) and other operating agreements 

modeled on that agreement, parties have developed 

comprehensive data exchange protocols to facilitate 

coordination and consistent AFC calculations. 

Much of this data is supplied through industry 

standard sources such as NERC SDX and NERC 

eTags. 

188SPP has developed seams agreements to 

exchange ATC data and coordinate congestion with 

non-RTO neighbors such as the Southwest Power 

Administration. Further, SPP exchanges ATC/AFC 

data and coordinates planning, reserve sharing, 

outage coordination, and transmission service 

administration under a transmission coordination 

agreement with Associated Electric Cooperative, 

Inc. (AECI), an individual transmission provider 

situated on SPP’s border that is not a member of 

SPP or any other RTO. 

189E.g., Allegheny, Constellation, and 

Indianapolis Power. 

190E.g., APPA, Bonneville, TAPS, and Seattle. 

constrained facilities. On constrained 

paths, where transmission equipment is 

stressed to its limits, Alcoa recommends 

that ATC be calculated on an hourly or 

real-time basis and be adjusted for 

temperature extremes. Seattle comments 

that ATC should be updated on a ‘‘by 

exception’’ basis, i.e., when significant 

model changes or confirmations of 

service requests occur. While 

supporting the Commission proposal, 

TAPS cautions against updating ATC/ 

AFC too frequently, as this may play 

into the hands of those who use 

reservation computer programs. 

Commission Determination 

301. The Commission adopts the 

NOPR proposal and requires the 

development of reliability standards 

that ensure ATC is calculated at 

consistent intervals among transmission 

providers. The Commission thus directs 

public utilities, working through NERC 

and NAESB, to revise reliability 

standard MOD–001 to require ATC to be 

recalculated by all transmission 

providers on a consistent time interval 

and in a manner that closely reflects the 

actual topology of the system, e.g., 

generation and transmission outages, 

load forecast, interchange schedules, 

transmission reservations, facility 

ratings, and other necessary data. This 

process must also consider whether 

ATC should be calculated more 

frequently for constrained facilities. 

ATC-related requirements for OASIS 

posting are discussed below. 

h. Data Exchange 

NOPR Proposal 

302. The Commission proposed the 

development through NERC of standard 

protocols that would enable and require 

the exchange of data and coordination 

among transmission providers. The 

Commission proposed that the 

following data, at a minimum, be 

exchanged among transmission 

providers for the purposes of ATC 

modeling: (1) Load levels; (2) 

transmission planned and contingency 

outages; (3) generation planned and 

contingency outages; (4) base generation 

dispatch; (5) existing transmission 

reservations, including counterflows; (6) 

ATC recalculation frequency and times; 

and (7) source/sink modeling 

identification. The Commission 

expressed its view that significant 

improvements in the communication, 

coordination, and exchange of data 

across all transmission providers in an 

interconnection are needed to produce 

accurate determinations of ATC. The 

Commission sought comment as to how 

much data sharing is workable, whether 

there are additional data that should be 

provided, whether access to such data 

should be limited to transmission 

providers, and if there are existing 

forums by which these or similar data 

are already shared. 

Comments 

303. Most commenters support the 

Commission’s proposal to establish 

rules for data exchange, but express a 

preference for confidential data 

exchange.186 NERC states that proposed 

changes to its existing modeling 

standards would require transmission 

providers to coordinate the calculation 

of TTC/ATC/AFC with others. TVA 

emphasizes that it has already 

incorporated these principles into its 

operating processes by executing 

agreements that provide for data 

exchange and coordination with 

neighboring transmission systems. 

304. PJM suggests that the data 

exchange protocols be developed as 

minimum requirements and not 

interfere with existing protocols that 

PJM has with neighboring control areas 

under agreements such as the MISO/ 

PJM JOA.187 Similarly, SPP states that it 

also has developed seams coordination 

agreements with adjoining transmission 

providers 188 that fully meet and, in 

some cases exceed, the Commission’s 

objective of fostering greater data 

exchanges between transmission 

providers. 

305. MISO is concerned that the 

NOPR does not address transparency 

and regional coordination issues arising 

at the seams between RTO and non-RTO 

regions, particularly with respect to 

ATC calculations. In MISO’s view, the 

Commission-approved joint operating 

agreements between various ISOs and 

RTOs contain cutting edge ATC 

calculation methodologies, while no 

comparable common protocols have 

evolved with non-RTO utilities. In its 

reply comments, Exelon agrees with 

MISO that the various joint operating 

agreements are not consistent. Exelon 

proposes that the NERC standards 

specify requirements for coordination 

and the type of data that must be 

exchanged and used for accurate ATC 

calculations. Exelon contends that 

having uniform standards for 

coordination developed by NERC will 

enhance efficiency throughout the 

industry, particularly between and 

among RTO and non-RTO areas. 

MidAmerican reiterates that ATC 

coordination remains an issue for RTOs 

and that any improvements in ATC 

coordination resulting from this 

proceeding must apply to the OATTs of 

RTOs and non-RTOs alike. 

306. NAESB states that coordination 

and data exchange may require business 

practices for existing transmission 

reservations, including counterflows, 

ATC calculation frequency, and source/ 

sink modeling identification. Some 

commenters request that the 

Commission clarify that only 

information necessary for purposes of 

ATC modeling needs to be 

exchanged.189 In particular, they 

propose that proprietary generation or 

market information data that might 

harm their competitive position should 

not be publicly disseminated since that 

would not enhance the ability of 

transmission providers to accurately 

calculate ATC. 

307. While acknowledging these 

confidentiality and commercial 

sensitivity concerns, other commenters 

recommend that the availability of 

shared data not be limited to 

transmission providers.190 For example, 

TAPS explains that transmission 

dependent utilities need an opportunity 

to access the data periodically as a 

check on the process. To address 

confidentiality or standards of conduct 

concerns, TAPS proposes that 

transmission dependent utilities’ access 

to data could be achieved through an 

employee barred from disclosing 

information to marketing staff or a third 

party independent consultant retained 

by the transmission dependent utility. 

However, APPA and Seattle urge the 

Commission to eliminate artificial and 

institutional barriers to the exchange of 

data and information. 

308. APPA and Seattle also contend 

that, even if data were openly available, 

the vast quantities of hourly data points 

are difficult to manage, process and 

analyze using existing methods. To 

address this issue, APPA recommends 


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191We are not requiring that every transmission 

provider follow identical protocols. Rather, all 

transmission providers must meet the relevant 

NERC reliability standards and NAESB business 

practices, and each entity will be subject to 

reliability standards compliance audits through 

which they will have to demonstrate that they meet 

or exceed the reliability standards. 

192E.g., Alberta Intervenors, AWEA, Bonneville, 

CAISO, Constellation, Duke, East Texas 

Cooperatives, ELCON, Entergy, Entegra, EPSA, 

E.ON, Exelon, MidAmerican, Morgan Stanley, 

Municipals, Nevada Companies, NPPD, PGP, PJM, 

Powerex, CREPC, Santee Cooper, TVA, TAPS, and 

TDU Systems. 

193E.g., Arkansas Municipal, Arkansas 

Commission, CAISO, Constellation, ELCON, 

Entergy, ISO New England, Morgan Stanley, 

NARUC, Nevada Companies, Occidental, PJM, 

Powerex, Project for Sustainable FERC Energy 

Policy, Santee Cooper, and Suez Energy NA. 

194E.g., EEI, PNM–TNMP, Sacramento, Seattle, 

and Southern. 

that the Commission encourage ongoing 

efforts to obtain greater resolution of 

system-model State variables, 

contractual uses and probabilistic 

ranges and to refine data management 

and analytical methods. 

309. New York Commission suggests 

having an overarching entity, such as a 

Transmission Oversight Center, that is 

responsible for calculating and 

coordinating ATC between various 

ISOs/RTOs could overcome this lack of 

data. 

Commission Determination 

310. The Commission adopts the 

NOPR proposal and directs public 

utilities, working through NERC, to 

revise the related MOD reliability 

standards to require the exchange of 

data and coordination among 

transmission providers and, working 

through NAESB, to develop 

complementary business practices. The 

following data shall, at a minimum, be 

exchanged among transmission 

providers for the purposes of ATC 

modeling: (1) Load levels; (2) 

transmission planned and contingency 

outages; (3) generation planned and 

contingency outages; (4) base generation 

dispatch; (5) existing transmission 

reservations, including counterflows; (6) 

ATC recalculation frequency and times; 

and (7) source/sink modeling 

identification. The Commission 

concludes that the exchange of such 

data is necessary to support the reforms 

requiring consistency in the 

determination of ATC adopted in this 

Final Rule. As explained above, 

transmission providers are required to 

coordinate the calculation of TTC/TFC 

and ATC/AFC with others and this 

requires a standard means of exchanging 

data. 

311. While there is a near consensus 

among commenters that significant 

improvements in the communication, 

coordination, and exchange of data 

across all transmission providers are 

needed to produce accurate 

determinations of ATC, we acknowledge 

the concerns of ISO/RTOs that new data 

exchange protocols may interfere with 

the existing protocols and seams 

coordination agreements. Although we 

will not provide a blanket exemption for 

ISOs and RTOs from meeting or 

exceeding the data exchange 

requirements of this Final Rule, they 

may, as explained in section IV.C.2, 

demonstrate in relevant filings that their 

existing data exchange protocols are 

consistent with or superior to those that 

are developed in the NERC and NAESB 

processes.191

312. With respect to concerns 

regarding the exchange of data that may 

be a subject of confidentiality and 

commercially sensitive, we only require 

information necessary for purposes of 

ATC modeling to be exchanged. As 

suggested by some commenters, 

proprietary generation or market 

information data that might harm a 

competitive position should not be 

publicly disseminated, since that would 

not enhance the ability of transmission 

providers to accurately calculate ATC. If 

any of the data are subject to 

confidentiality and are commercially 

sensitive, they must be disclosed in 

accordance with a confidentiality 

agreement. 

2. Transparency 

a. OATT Transparency 

(1) Attachment C 

NOPR Proposal 

313. In the NOPR, the Commission 

proposed to require each transmission 

provider to include in Attachment C of 

its OATT more descriptive information 

concerning its ATC/AFC calculation 

methodology. Specifically, the 

Commission proposed to require the 

transmission provider to state its 

specific mathematical algorithm used to 

calculate firm and non-firm ATC/AFC 

for its scheduling horizon, operating 

horizon, and planning horizon. The 

Commission also proposed to require 

transmission providers to provide a 

process flow diagram that illustrates the 

various steps through which ATC/AFC 

is calculated. In addition, the 

Commission proposed to require 

transmission providers to provide 

definitions and explain in detail how 

TTC, ETC, AFC, TRM, and CBM are 

calculated for both operating and 

planning horizons. 

Comments 

314. Most commenters support the 

Commission’s overall proposal on 

transparency in ATC calculations.192

Numerous commenters support the 

Commission’s proposal to require 

detailed information in Attachment C 

regarding the transmission provider’s 

ATC/AFC calculation methodology.193

Barrick agrees in its reply comments 

that a thorough explanation of how ATC 

is calculated should be made readily 

available either in the transmission 

provider’s OATT or on its OASIS, 

thereby improving transparency and 

making it less difficult for customers to 

determine whether the calculations are 

unduly discriminatory. Old Dominion 

calls for greater transparency in the 

details of calculating ATC, even as 

applied to RTOs such as PJM because of 

the relevance of ATC at the borders of 

an RTO/ISO and the market impact of 

inconsistencies in definitions, data, 

modeling assumptions and frequency of 

ATC calculations. NERC states that the 

revised NERC reliability standards will 

address transparency. 

315. NARUC contends that 

understanding ATC calculation 

methodologies and having access to the 

underlying data is essential to a range of 

critical State commission functions and, 

therefore, greater transparency of ATC 

information will significantly enhance 

State commissions’ abilities to fulfill 

their statutory obligations. On reply, 

North Carolina Agencies agree with 

NARUC and state that efforts aimed at 

increased transparency of ATC 

calculations should help uncover any 

actual discriminatory behavior by 

transmission providers, provide a 

clearer standard against which to 

evaluate claims of unduly 

discriminatory activities, and facilitate 

regional planning efforts. Entegra states 

on reply that transmission providers 

should be required to post narratives 

explaining changes in models and 

factors underlying ATC and AFC values, 

which would be invaluable to the 

Commission and customers in 

identifying problems that may warrant 

enforcement actions. 

316. While APPA generally supports 

the Commission’s proposal, some of 

APPA’s members along with other 

commenters express concern that 

including all the information might be 

too burdensome and result in numerous 

tariff changes.194 Some APPA members 

in the West also express concerns about 

the competitive implications of 


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providing such confidential and 

sensitive information. 

317. EEI also notes that providing 

additional detailed information in 

Attachment C would be duplicative and 

may result in confusion due to 

inconsistencies between the wording of 

the NERC and NAESB ATC documents 

and each transmission provider’s 

Attachment C. To avoid uncertainty, EEI 

recommends that the Commission 

require transmission providers to 

comply with the requirements of 

Attachment C by referencing NERC 

reliability standards or business 

practices that provide the information 

that is called for in the Attachment. 

MidAmerican believes that additional 

information concerning calculating ATC 

and its components would best be 

retained in the transmission provider’s 

business practices rather than 

Attachment C. In its reply comments, 

Powerex suggests an alternative of 

permitting transmission providers to 

provide a general reference to NERC, 

WECC, or NAESB standards and fully 

outline core definitions, processes, data 

and assumptions when deviating from 

such standards. 

318. Southern contends that the 

transparency concerns expressed in the 

NOPR are driven more by the 

complexity and volume of the data 

involved rather than a lack of 

information. Southern suggests that 

sufficient information is readily 

available and the best course of action 

by the Commission would be to focus 

on documenting transfer capability 

methodologies available to transmission 

customers. NRECA replies that many 

commenters provided input into why 

more transparency is needed and 

repeats the example provided in its NOI 

comments of a cooperative that spent 

many months in discussions with a 

public utility transmission provider in 

an effort to understand ATC-related 

information posted on OASIS. 

319. Pinnacle contends that the 

Commission’s proposal for detailed 

information in Attachment C is only 

relevant in flow-based systems, pointing 

out that in the Western Interconnection, 

the scheduling horizon, and the 

operating horizon are the same and thus 

reporting such information is not 

necessary. APPA and Bonneville believe 

that adding such detail in Attachment C 

may only result in incremental changes 

and suggest that better regional 

coordination would provide greater 

transparency. 

320. Though ISO New England 

believes this proposal would not create 

an undue burden, it urges the 

Commission to allow for variety in the 

illustration of the process flow diagram. 

Regarding the proposal to require a 

‘‘detailed explanation’’ of the 

calculation of ATC, TTC, ETC, and TRM 

components, ISO New England argues 

that the relevant inputs can change on 

a daily basis because ATC for Pooled 

Transmission Facilities (PTF) in New 

England is a function of market 

conditions, as opposed to an 

administratively-derived calculation. In 

ISO New England’s view, the level of 

detail required should reflect the 

operation of competitive markets. MISO 

is concerned that the NOPR does not 

address transparency and regional 

coordination issues arising at the seams 

between market and non-market areas, 

particularly with respect to ATC 

calculations. 

321. MidAmerican strongly urges the 

Commission to ensure that non-public 

utility transmission providers adhere to 

the transparency requirements, since in 

the Pacific Northwest many of the 

‘‘backbone’’ transmission lines are coowned by jurisdictional and 

nonjurisdictional entities. A 

jurisdictional co-owner may be limited 

in its ability to determine such 

parameters as TRM and CBM because it 

may not be the line operator. LPPC, in 

its reply comments, believes it is 

unnecessary and redundant to require 

non-public utility transmission 

providers to adopt the ATC 

requirements of the pro forma OATT, 

because the Commission recognizes in 

the NOPR that NERC and NAESB are 

currently drafting standards for ATC, 

which when final will be filed with the 

Commission and become part of the 

ERO’s mandatory reliability standards 

and fully applicable to otherwise 

nonjurisdictional entities. 

322. Suez Energy NA contends that it 

is essential that the Commission include 

an explanation of each component of 

the ATC calculation in Attachment C to 

ensure that the transmission provider 

incorporates NERC standards 

appropriately and to ensure proper 

enforcement in the event that an audit 

shows that the transmission provider 

has employed other methods of 

calculating ATC. Suez Energy NA also 

notes that the mathematical algorithms 

and process flow diagrams should be 

provided to users of the transmission 

system, independent monitors, 

transmission coordinators and 

regulators, even if a confidentiality 

agreement is required. APPA suggests 

that the Commission and regional 

reliability organizations conduct 

additional audits to ensure that these 

posted practices and procedures are in 

fact being followed, and that the data 

used are verifiable. 

Commission Determination 

323. The Commission adopts the 

NOPR proposal to increase transparency 

regarding ATC calculations by requiring 

each transmission provider to set forth 

its ATC calculation methodology in its 

OATT. Each transmission provider 

must, at a minimum, include the 

following information in Attachment C 

to its OATT. It must clearly identify 

which of the NERC-approved 

methodologies it employs (e.g., contract 

path, network ATC, or network AFC). It 

also must provide a detailed description 

of the specific mathematical algorithm 

the transmission provider uses to 

calculate firm and non-firm ATC for the 

scheduling horizon (same day and realtime), operating horizon (day ahead and 

pre-schedule), and planning horizon 

(beyond the operating horizon). In 

addition, transmission providers must 

include a process flow diagram that 

describes the various steps that it takes 

in performing the ATC calculation. 

Furthermore, transmission providers 

must set forth a definition of each ATC 

component (i.e., TTC, ETC, TRM, and 

CBM) and a detailed explanation of how 

each one is derived in both the 

operating and planning horizons. 

Requiring transmission providers to file 

a statement of their ATC calculation 

methodology along with a process flow 

diagram and more detailed definitions 

of ATC components in Attachment C of 

the OATT will provide greater 

transparency to transmission customers 

and assist in identifying any 

discrepancies that may arise in ATC 

determinations. These new 

requirements will assist in alleviating 

any appearance of discrimination in the 

determination of ATC. 

324. The Commission acknowledges 

NARUC’s comments that understanding 

ATC methodologies and the underlying 

data also will enhance State regulators’

ability to meet their regulatory 

obligations. More transparent ATC 

calculations are critical to coordinated 

regional transmission planning that 

ultimately will improve transmission 

access for customers and enhance grid 

reliability. Transparent ATC 

calculations facilitate the ability of 

market participants and regulators to 

detect discrimination. 

325. We do not believe our 

requirement to include additional 

information in Attachment C will be 

overly burdensome or lead to an 

excessive level of future tariff revisions. 

Attachment C must provide an accurate 

documentation of processes and 

procedures related to the calculation of 

ATC, not the actual mathematical 

algorithms themselves, which should be 


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195WECC has on file a Reliability Management 

System agreement under which transmission 

providers agreed, through contracts, to follow 

WSCC reliability criteria. Western Systems 

Coordinating Council, 87 FERC ¶ 61,060 (1999). 

196The Commission recognized in Order No. 889 

that the methodology for calculating ATC and TTC 

belongs in the tariff. Order No. 889 at 31,607. At 

the time, the industry represented that it was 

engaged in efforts to develop uniform methods of 

determining ATC. The Commission encouraged 

such industry efforts and required that the tariff 

include the methodology, which was to be based on 

current industry practices, standards and criteria. 

197For the same reason, the Commission 

disagrees with the assertions of Southern and EEI 

that more information in Attachment C would be 

duplicative because some ATC-related information 

is already available elsewhere. 

198Capacity Benefit Margin in Computing 

Available Transmission Capacity, 88 FERC ¶ 61,099 

(1999) (CBM Order). 

posted on the transmission provider’s 

Web site. These processes define service 

availability and, as such, must be part 

of the transmission provider’s OATT. It 

is entirely appropriate that, because 

revisions to such processes impact 

transmission availability, they should be 

filed for Commission approval and 

included in a transmission provider’s 

OATT. We also require transmission 

providers to file a revised Attachment C 

to incorporate any changes in NERC’s 

and NAESB’s revised reliability 

standards and business practices related 

to ATC calculations, as requested by the 

Commission in this Final Rule. This 

filing should be made within 60 days of 

completion of the NERC and NAESB 

processes. As we expect transmission 

providers to rarely change their ATC 

calculation methodologies, we do not 

believe this requirement will trigger an 

unacceptable level of tariff filings 

modifying the Attachment C description 

of the ATC components and processes. 

326. We agree with ISO New England 

that the process flow diagram 

requirement may be met with a variety 

of illustrations, so long as it is of 

sufficient detail to provide the 

transmission customer with a 

reasonable understanding of the 

transmission provider’s ATC calculation 

processes. The process flow diagram 

should support the other Attachment C 

requirements. As noted above, we agree 

with Suez Energy NA that mathematical 

algorithms and process flow diagrams 

should be made available. We do not 

find that a confidentiality agreement is 

generically warranted; however, we note 

that, a transmission provider may 

require a confidentiality agreement for 

CEII materials, consistent with our CEII 

requirements, or may otherwise protect 

the confidentiality of proprietary 

customer information. 

327. We also require transmission 

providers to document their processes 

for coordinating ATC calculations with 

their neighboring systems. This 

requirement is particularly important 

with respect to seams between market 

and non-market areas, as identified by 

MISO, and with respect to the request 

of other commenters to increase regional 

coordination regarding ATC calculation. 

While this Final Rule does not address 

all seams issues between market and 

non-market areas, it does take important 

steps towards that end by improving 

data exchange between transmission 

providers and providing increased 

transparency with respect to ATC 

calculation. 

328. We reject proposals to address 

the transparency of ATC methodology 

by merely referencing business practices 

and reliability standards developed by 

NERC, NAESB, and WECC.195 ATC 

calculations have a direct and tangible 

effect on the granting of open access 

transmission service.196 As such, an 

accurate and detailed statement of the 

methodology and its components that 

defines how the transmission provider 

determines ATC belongs in the 

transmission provider’s OATT as the 

means of holding the transmission 

provider accountable for following nondiscriminatory procedures for granting 

service, not in business practices kept 

by the transmission provider.197

However, as noted above, the actual 

mathematical algorithms should be 

posted on the transmission provider’s 

web site, with the link noted in the 

transmission provider’s Attachment C. 

329. We also reject Pinnacle’s 

assertion that more detailed information 

in Attachment C would only apply to 

flow-based systems. Regardless of what 

type of ATC calculation methodology is 

employed, transparency in ATC 

calculations is critical to avoid undue 

discrimination when allocating 

transmission capacity under the pro 

forma OATT. 

330. In response to MidAmerican’s 

comments regarding the applicability of 

the ATC-related reforms to non-public 

utilities, we again refer to section IV.C.3 

where we discuss this issue generally. 

We note here, however, that the ERO’s 

reliability standards currently in 

development before the Commission 

will be applicable to all users, owners 

and operators of the bulk electric grid, 

which includes non-public utilities. 

331. We do not believe ATC-specific 

tariff audits are necessary to order at 

this time. The Commission will 

continue to provide oversight of all 

tariff-related activities through its 

enforcement program. Moreover, ATC 

requirements will be part of the 

mandatory and enforceable reliability 

standards and, as such, will be subject 

to compliance audits through that 

process. 

(2) CBM Practices 

NOPR Proposal 

332. In the CBM Order, the 

Commission required transmission 

providers to post a specific narrative 

explanation of their CBM practices.198

In addition, the Commission directed 

transmission providers to post their 

procedures for allowing access to CBM 

during emergencies. The Commission 

further stated in the CBM Order that, if 

a utility’s practice was not to set aside 

transfer capability as CBM, it should 

reflect that in Attachment C. 

333. In the NOPR, the Commission 

proposed to require transmission 

providers to include this CBM narrative 

in Attachment C of their OATTs. In 

addition, the Commission proposed that 

transmission providers explain their 

definition of CBM, list the databases 

used in their CBM calculations, and 

prove that there is no double-counting 

of contingency outages when 

performing CBM calculations. 

Comments 

334. Seattle and Suez Energy NA 

support this proposal. Seattle states that 

CBM information should be specified in 

Attachment C in order to provide clear 

guidance for the specific information 

that is posted on OASIS. Seattle and 

APPA suggest that CBM should be 

verifiable and subject to audit by 

independent parties such as regional 

reliability organizations. 

335. EEI suggests that the Commission 

revise Attachment C, section 3(f) to 

replace the word ‘‘prove’’ with the word 

‘‘demonstrate’’ in the requirement that 

the transmission provider ‘‘prove’’ that 

it does not double count contingency 

outages when calculating CBM, TTC 

and TRM. EEI notes that the term 

‘‘prove’’ implies a determination on the 

merits after evaluation of competing 

arguments and evidence. A transmission 

provider should be able to satisfy its 

obligations by ‘‘demonstrating’’ the 

absence of a double count. Any 

customer that wishes to challenge the 

demonstration can do so, at which time 

the issue of ‘‘proof’’ would arise. 

336. With regards to ‘‘double 

counting,’’ TVA references TRM and 

agrees that additional explanations 

regarding the calculation of TRM, 

including methods used to avoid double 

counting contingency events, should 

improve transparency in providing open 

access transmission service. TVA points 

out that this is being addressed by a 

NERC standards drafting team. 


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199E.g., APPA, Constellation, FirstEnergy, 

Indianapolis Power, Sacramento, Suez Energy NA, 

TAPS, and TDU Systems. 

Commission Determination 

337. The Commission adopts the 

NOPR proposal requiring additional 

information in the transmission 

provider’s OATT Attachment C 

regarding its determination of CBM. 

Transmission providers must provide in 

Attachment C a narrative description 

detailing their CBM practices. In 

addition, a transmission provider must 

explain its definition of CBM and list 

the databases used to derive its value. 

These new requirements will provide 

transmission customers transparency 

into the CBM component of ATC and 

help discourage the potential for undue 

discrimination in the calculation and 

use of CBM. 

338. We adopt EEI’s proposal that the 

Commission revise Attachment C, 

section 3(f) to replace the word ‘‘prove’’

with the word ‘‘demonstrate.’’ The word 

‘‘demonstrate’’ more accurately 

describes the showing we expect the 

transmission provider to make. We 

agree that the word ‘‘prove’’ implies a 

standard of proof that we did not intend 

to impose. We also acknowledge TVA’s 

comments that the NERC standards 

drafting team is developing standards 

that should address ‘‘double counting’’

in ATC calculations in general. 

However, we require that the 

information in Attachment C be 

sufficient to demonstrate that a 

transmission provider is not double 

counting CBM in its ATC calculation. 

339. Finally, the Commission rejects 

the proposal by Suez Energy NA, APPA, 

and Seattle to establish formal audits of 

CBM set asides. Requirements for CBM 

will be part of the mandatory and 

enforceable reliability standards and, as 

such, will be subject to compliance 

audits through that process. Moreover, 

the Commission provides oversight of 

all tariff-related activities through its 

enforcement program. 

b. OASIS 

(1) ATC/TTC Posting Requirements 

NOPR Proposal 

340. The Commission’s existing 

regulations require certain ATC-related 

information to be posted on each 

transmission provider’s OASIS and 

other information to be provided on 

request. To ensure that relevant 

information is available on a timely 

basis to all market participants, the 

Commission proposed in the NOPR to 

amend its regulations to allow potential 

customers greater access to information 

that will enable them to obtain service 

on a non-discriminatory basis from any 

transmission provider. 

341. The Commission noted in the 

NOPR that existing regulations require 

ATC and TTC calculations to be 

performed according to consistently 

applied methodologies referenced in the 

transmission provider’s OATT and 

current industry practices, standards 

and criteria. The Commission proposed 

that these calculations be based on the 

ERO reliability standards. 

342. The Commission further 

proposed to maintain the requirement 

that transmission providers provide, on 

request, all data used to calculate ATC 

and TTC for any constrained paths. 

Transmission providers also would 

remain required, on request, to make 

publicly available any system planning 

studies or specific network impact 

studies performed for customers and to 

post a list of such studies on OASIS. 

Comments 

343. Several commenters support the 

proposal to post ATC-related 

information on OASIS.199 TDU Systems 

supports each of the Commission’s 

proposals with respect to providing 

easier access to data underlying ATC 

calculations and greater transparency to 

the process. Sacramento states that 

posting on OASIS will ensure proper 

public access, but will avoid the need 

for Commission approval of an OATT 

change. 

344. Constellation strongly supports 

the need for additional transparency, 

stating that providing transmission 

customers with meaningful insight into 

the current ‘‘black box’’ determination 

of ATC will help minimize the mystery 

underlying many transmission provider 

responses to service requests. According 

to Constellation, further transparency 

will assist customers in predicting the 

outcome of transmission service 

requests and facilitate increased 

commercial activity. Constellation 

suggests that the Commission require 

transmission providers to provide 

transmission customers, on request, 

with specific details related to modeling 

data, modeling support information, 

modeling benchmarking and forecasting 

data, and transmission service request 

audit data. It requests that the 

information be in a form and format 

usable by the transmission customers 

and that the Commission take steps to 

ensure that transmission customers 

understand how ATC is calculated and 

the data inputs are used to affect those 

calculations. 

345. Great Northern likewise requests 

that the Commission enhance the 

requirement to provide all data on 

request, specifically on constrained 

paths, by requiring a posted tabulation 

of annual and monthly ATC calculation 

details. Great Northern suggests 

including TTC, network load for each 

transmission customer, capacity 

reserved for each network resource, 

each point-to-point transmission service 

reservation, CBM and other deductions 

from TTC. 

346. APPA members support the 

posting of ATC information, as it will 

assist in using ATC more efficiently, 

and they support the posting of system 

planning studies and specific network 

impact studies that the transmission 

provider performs for its own merchant 

function, as well as studies performed 

for customers. In addition, APPA 

suggests the posting of facilities studies 

at the time they become available, 

assuming that this can be done 

consistent with CEII concerns. TAPS 

goes further by urging the Commission 

to close gaps in the current OASIS 

requirements by requiring posting of all 

studies performed for transmission 

owners’ own transmission network 

resource designations and other uses of 

the system, including facilities studies 

as well as system impact studies, 

ensuring posted study lists are updated 

contemporaneously with the availability 

of new studies, and requiring retention 

of studies for a minimum of five years. 

347. Nevada Companies and TVA 

support cost effective measures that 

increase transparency in transmission 

operations and, unless the requirement 

becomes unduly time consuming or 

burdensome, in general support more 

disclosure rather than less. 

Commission Determination 

348. The Commission adopts the 

proposal in the NOPR to continue to 

require transmission providers to 

comply with existing ATC-related 

posting obligations as supplemented by 

this Final Rule. The Commission will 

continue to require transmission 

providers, on request, to make available 

all data used to calculate ATC and TTC 

for any constrained paths and any 

system planning studies or specific 

network impact studies performed for 

customers. Transmission providers must 

also continue to post a list of such 

studies on OASIS. 

349. In addition, we agree with the 

requests of APPA and TAPS to require 

the additional posting of, at a minimum, 

a listing of all system impact studies, 

facilities studies, and studies performed 

for the transmission provider’s own 

network resources and affiliated 

transmission customers, to be made 

available upon request. We note that 

appropriate procedures to accommodate 

CEII concerns should be developed to 


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200E.g., Powerex, PJM, PPL, Seattle, and Pinnacle. 

201CBM Order at 61,237. 

202 Id. 

203E.g., EPSA, Sacremento, Santa Clara, Suez 

Energy NA, and TDU Systems. 

204CBM Order at 61,237. 

205The MOD–005 reliability standard establishes 

the procedure for verifying CBM values. 

ensure eligible entities with a legitimate 

interest in transmission study data can 

receive access to it. Also, we adopt 

TAPS’ suggestion that the studies be 

made available for five years to make 

the requirement consistent with data 

retention requirements pertaining to 

denial of service requests. 

350. The Commission rejects 

Constellation’s and Great Northern’s 

proposals to require transmission 

providers to provide upon request or 

regularly post additional information 

beyond that required in the regulations 

and this Final Rule. The transmission 

provider is already required to make 

available, upon request and in 

electronic format, all information 

related to the calculation of ATC and 

TTC for any constrained path. 

Accordingly, we see little benefit to 

require transmission providers to 

provide upon request or regularly post 

additional information suggested by 

these commenters. 

(2) CBM/TRM Posting Requirements 

NOPR Proposal 

351. The Commission’s OASIS 

regulations currently require 

transmission providers to calculate and 

post ATC and TTC for each posted path, 

but make no requirement for CBM and 

TRM postings. In the CBM Order, 

however, the Commission required 

transmission providers, with respect to 

each path for which the utility already 

posts ATC, to post (and update) the 

CBM figure for that path. The 

Commission also required transmission 

providers to make any transfer 

capability set aside for CBM available 

on a non-firm basis and to post this 

availability on OASIS. In the NOPR, the 

Commission proposed to incorporate 

these CBM posting requirements into its 

regulations. The Commission also 

proposed that transmission providers 

post (and update) the TRM values for 

the paths on which the transmission 

provider already posts ATC, TTC, and 

CBM. 

Comments 

352. Several commenters strongly 

support the Commission’s proposal to 

require transmission providers to post 

TRM and CBM.200 APPA and EPSA 

agree that the posting of TRM for near 

term transmission services would 

provide greater assurance that ATC 

calculations are being performed 

according to established procedures. 

Since transmission providers already 

have this information, FirstEnergy states 

that it does not appear to be unduly 

burdensome for them to post such 

information. Bonneville indicates that it 

currently posts TRM values in its 

Business Practices Forum, which is 

useful for examining curtailment events, 

supporting transmission planning 

objectives, and validating posted ATC 

values. 

353. EPSA also recommends that the 

Commission provide guidance on 

standards that should be developed to 

require each transmission provider to 

notify the Commission in writing and 

post a notice on its OASIS within 24 

hours of a transmission provider’s use of 

CBM to import emergency power. EPSA 

also requests that the amount of CBM 

reserved for each interface be posted on 

OASIS. 

Commission Determination 

354. The Commission adopts the CBM 

posting requirements proposed in the 

NOPR. In doing so, we amend our 

OASIS regulations to incorporate the 

directives established in the CBM Order. 

Accordingly, we require transmission 

providers to post (and update) the CBM 

amount for each path. In addition, the 

Commission requires transmission 

providers to make any transfer 

capability set aside for CBM but unused 

for such purpose available on a non-firm 

basis and to post this availability on 

OASIS. Furthermore, the Commission 

requires transmission providers to post 

(and update) the TRM values for the 

paths on which the transmission 

provider already posts ATC, TTC, and 

CBM. 

355. We reject EPSA’s request to 

require transmission providers to notify 

the Commission in writing and post a 

notice on OASIS within 24 hours of a 

transmission provider’s use of CBM to 

import emergency power and transfer 

capability set aside as CBM at each of 

the transmission provider’s interfaces. 

The additional transparency of CBMrelated information provided in this 

Final Rule, along with the reforms 

related to consistency of CBM, will 

cause sufficient information to be made 

available to customers concerning the 

use of CBM. The use and allocation of 

CBM and TRM will be more transparent 

to transmission customers, thus 

reducing the potential for undue 

discrimination. 

(3) Periodic Reevaluation of the CBM 

Set-Aside 

NOPR Proposal 

356. In the CBM Order, the 

Commission stated that the level of ATC 

set aside for CBM can and should be 

reevaluated periodically to take into 

account more certain information (such 

as assumptions that may not have, in 

fact, materialized).201 The Commission 

therefore directed transmission 

providers to periodically reevaluate 

their generation reliability needs so as to 

make known the availability of CBM 

and to post on OASIS their practices in 

this regard.202 In the NOPR, the 

Commission proposed to incorporate 

these requirements in the Commission’s 

regulations and to obligate transmission 

providers to reevaluate the CBM setaside at least quarterly. 

Comments 

357. Some commenters support 

quarterly reevaluation of CBM setasides.203 TAPS agrees with the need for 

full transparency of CBM reservations 

and practices and states that, because 

CBM values may differ from season to 

season, CBM values should be 

separately calculated for at least each 

quarter. However, TAPS does not find 

that it is necessary or appropriate for the 

CBM values to be reevaluated quarterly, 

given the effort involved in collecting 

the data and performing the modeling 

analysis. Rather, CBM studies should be 

performed at least every other year, 

supplemented with ‘‘off-year studies’’

when appropriate. 

Commission Determination 

358. The Commission incorporates 

into its regulations the requirement in 

the CBM Order for a transmission 

provider to periodically reevaluate its 

transfer capability set-aside for CBM. 

With respect to TAPS’ concerns over the 

effort involved in the re-evaluation 

process, we will require CBM studies to 

be performed at least every year. This 

requirement is consistent with the CBM 

Order, in which the Commission stated 

that the level of ATC set aside for CBM 

should be reevaluated periodically to 

take into account more certain 

information (such as assumptions that 

may not have, in fact, materialized).204

While changes requiring a reevaluation 

of CBM are longer-term in nature (e.g., 

installation of a new generator or a longterm outage), quarterly may be too 

frequent, though two years may be too 

long and may prevent a portion of the 

CBM set-aside from being released as 

ATC. Moreover, annual reevaluation is 

consistent with the current NERC 

standard being developed in MOD–

005.205 The requirement to evaluate 

CBM at least every year also is 

consistent with the CBM Order in that 


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12312 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

206See 18 CFR 37.6(b)(3)(i)(C). 

207E.g., Arkansas Commission, CAISO, 

Constellation, East Texas Cooperatives, Exelon, 

FirstEnergy, LPPC, Morgan Stanley, NRECA, 

Pinnacle, Powerex, Santa Clara, and Suez Energy 

NA. 

208E.g., Ameren, ISO New England, Southern, 

and NRECA. 

209E.g., Ameren, EEI, Entergy, MISO, Pinnacle, 

PJM, PNM–TNMP, Southern, TranServ, and TVA. 

210E.g., APPA, East Texas Cooperatives, Suez 

Energy NA, and TAPS. 

211November 2, 2006, Addendum to the 

Testimony of Ronald M. Mucci on behalf of the 

North American Energy Standards Board, 

Preventing Undue Discrimination and Preference in 

Transmission Service, Docket Nos. RM05–25–000 

and RM05–17–000, October 12 Technical 

Conference, pp. 2–3. 

the Commission directed transmission 

providers to periodically reevaluate 

their generation reliability needs so as to 

make known the need for CBM and to 

post on OASIS their practices in this 

regard. 

(4) ATC/TTC Narrative Explanation 

NOPR Proposal 

359. In the NOPR, the Commission 

proposed to largely retain existing 

posting requirements for unconstrained 

posted paths, but to amend the 

regulations relating to data posted for 

constrained posted paths. Existing 

regulations require ATC and TTC on 

constrained paths to be updated when 

(1) Transactions are reserved, (2) service 

ends, or (3) whenever the TTC estimate 

for the path changes by more than 10 

percent.206 In the NOPR, the 

Commission proposed to supplement 

the existing regulations by requiring the 

transmission provider to post a brief, 

but specific, narrative explanation of the 

reason for the change at the time a 

change in monthly and yearly ATC 

values on a constrained path is posted. 

The Commission sought comment on 

whether the posting of this new 

information would provide adequate 

transparency to the customer on a 

frequent enough basis without imposing 

an undue burden on the transmission 

provider. The Commission also sought 

comment on whether a similar narrative 

should be required when ATC remains 

unchanged at a value of zero for some 

specified period of time. 

Comments 

360. Some commenters support the 

Commission’s proposal to require 

transmission providers to post more 

detailed explanations about changes in 

ATC values on their OASIS sites.207

NAESB, TranServ, and Williams request 

that the Commission clarify the 

regulatory requirements for posting of 

updated ATC values such as the level of 

standardization, frequency and time of 

postings, and other requirements. 

CAISO believes that ATC should be 

updated on a daily basis. 

361. Powerex and Nevada Companies 

propose that additional disclosures be 

posted, such as data on grandfathered 

contracts, time-specific data relevant to 

transmission constraints and ATC rights 

on posted paths, and remaining 

customer rights under a reservationbased network service system. 

362. A few commenters caution that 

some of the data that the Commission is 

requiring to be posted by transmission 

providers is market-sensitive and, if 

posted on a real-time basis, could be 

used by third parties to obtain an unfair 

competitive advantage.208 These 

commenters propose that the 

transmission providers should be 

allowed a brief period of delay (e.g., one 

week) before posting data. Indianapolis 

Power also advocates a delay due to the 

burden on transmission providers of the 

new posting. 

363. Several commenters oppose the 

Commission’s proposal to require that 

transmission providers post narratives 

on OASIS outlining reasons why 

monthly and yearly ATC values on 

constrained paths change.209 These 

commenters contend that this will cause 

undue burden on transmission 

providers without providing customers 

with any significant or new information. 

They also argue that the proposal is 

impractical and will not result in 

providing transmission customers with 

meaningful information regarding 

transmission service options. 

364. If such a requirement is adopted, 

MISO recommends that a threshold 

higher than a 10 percent change in ATC 

be established and that the Commission 

clarify what the term ‘‘specific 

explanation’’ means in this context. PJM 

states that it already exceeds the 

Commission’s proposed requirement. 

However, if strictly applied, this 

proposal would be unduly burdensome 

on PJM because it would require PJM to 

post a narrative each hour. PJM asks that 

the Commission not apply unnecessary 

and costly posting requirements on 

independent RTOs and ISOs. 

365. EEI and Southern are concerned 

that monthly ATC may change in 

response to every reservation of hourly 

transmission service because a 

reservation of hourly firm service on a 

constrained path may reduce the 

availability of monthly firm service. EEI 

contends that, if transmission providers 

are required to post changes in TTC 

instead of ATC, they would not be 

required to post a new narrative every 

time a reservation is made, thus 

reducing the overall burden on 

transmission providers. EEI additionally 

states that the reasons for changes in 

TTC and ATC values often are complex 

and involve the interaction of multiple 

variables in the model that produces the 

TTC and ATC values and a specific 

change in TTC or ATC cannot easily be 

traced to a specific change in the inputs. 

Alternatively, EEI suggests that 

transmission providers could post the 

major changes in the inputs to the TTC 

modeling software that are made in 

connection with each updated TTC 

posting without ascribing specific 

inputs to specific changes in TTC and 

ATC values on specific lines. 

366. Several commenters are 

supportive of the proposed requirement 

that transmission providers provide a 

narrative explanation when ATC values 

remain at zero.210 APPA suggests that if 

a particular interface shows an ATC of 

zero for a specified period, the 

transmission provider should provide a 

narrative explanation of why this is the 

case and how its plans to address this 

problem. It also suggests that this 

information should be employed in the 

transmission planning process. East 

Texas Cooperatives, in reply comments, 

state that the narrative can provide 

useful information to the transmission 

customers and State and Federal 

regulators regarding specific conditions 

regarding ATC coordination. 

367. In supplemental comments, 

NAESB states that the Commission 

should specify whether it is sufficient 

for the explanation of changes in ATC 

or TTC values to be limited to broad 

generalized statements or whether the 

posted information should include such 

information as the specific events which 

gave rise to the change, the new values 

for ATC at all points on the network, the 

impact of the change on transmission 

customers, and a detailed snapshot of 

the conditions on the system at all 

flowgates or constrained elements when 

the change occurred.211

368. Southern states that posting a 

narrative when ATC remains at zero is 

unwarranted and unnecessary, as it 

simply indicates that the market has 

responded to market signals of ATC 

availability and purchased all available 

capacity. 

Commission Determination 

369. The Commission adopts the 

NOPR proposal, with the modifications 

discussed below, to require that the 

transmission provider post a brief, but 

specific, narrative explanation of the 

reason for a change in monthly and 

yearly ATC values on a constrained 

path. Rather than requiring a narrative 


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212E.g., APPA, Arkansas Commission, Arkansas 

Municipal, Duke, East Texas Cooperatives, MISO, 

ISO New England, Williams, Nevada Companies, 

PPL, Sacremento, Sant Clara, Suez Energy NA, and 

TDU Systems. 

213E.g., MidAmerican, PacifiCorp, PNM–TNMP, 

and PJM. 

when a monthly or yearly ATC value 

changes as a result of transactions being 

reserved, service ending, or the TTC 

estimate for the path changing by more 

than 10 percent, we will require a 

narrative when a monthly or yearly ATC 

value changes only as a result of a 10 

percent change in TTC. This will reduce 

the number of ATC changes for which 

a narrative will be required and address 

concerns that the new requirement 

unduly burdens transmission providers. 

Any remaining burden is justified by the 

benefit to transmission customers of 

receiving timely information regarding 

changes in TTC that result in changes to 

ATC. In addition, we adopt NAESB’s 

suggestion that posted information 

include the (1) Specific events which 

gave rise to the change and (2) new 

values for ATC on that path (as opposed 

to all points on the network). 

370. We reject calls for delays prior to 

posting data. While commenters allege 

the possibility of granting others a 

competitive advantage through the 

release of ‘‘market-sensitive’’ data, they 

have proffered no evidence to support 

the allegation of potential harm. 

371. We do require, as suggested in 

the NOPR, a narrative with regard to 

monthly or yearly ATC values when 

ATC remains unchanged at a value of 

zero for a significant period, and will set 

that period at six months or longer. This 

information will be valuable to 

customers and regulators in assessing 

the ability of a transmission provider’s 

facilities to meet existing service 

requests. The information also will 

provide assurance to customers that the 

transmission provider is diligent in 

regularly evaluating ATC on all paths, 

monitoring persistent constraints and 

addressing them in its planning 

processes. 

372. Finally, we reject CAISO’s 

suggestion that ATC be updated daily 

on a transmission provider’s OASIS site, 

because CAISO offered no justification 

for the proposal. 

(5) Denial of Service/Records Retention 

NOPR Proposal 

373. In the NOPR, the Commission 

proposed to maintain the requirement 

that a transmission provider post the 

reason for a denial of a request for 

service. The Commission also proposed 

to amend this provision to require a 

transmission provider to maintain and 

make available information supporting 

the reason for the denial. The 

Commission further proposed to extend 

the time period for which transmission 

providers must maintain transmission 

service information for audit. Currently, 

regulations require that audit data be 

retained and made available upon 

request for download for three years 

from the date when they are first posted. 

The Commission proposed to change 

the period from three to five years. 

Comments 

374. Many commenters support 

posting of the reasons for denying 

service and the 5-year retention 

proposal.212 TAPS supports the 

proposal but suggests several 

modifications. First, it suggests that the 

Commission clarify the requirement to 

post the reasons for denying service is 

triggered not only by denial of the 

entirety of a transmission request, but to 

any disposition that falls short of a full 

unconditional grant of the service (with 

rollover rights if applicable). Second, 

TAPS recommends that the regulatory 

text of proposed section 37.6(e)(2)(ii) be 

modified to make the supporting data 

available, upon request, to any eligible 

customer rather than just to the 

customers who were denied service. 

Third, it asks that the Commission 

expand its OASIS regulations to require 

the transmission provider to maintain 

and make available on request the 

information supporting the disposition 

(positive, negative, or in between) of its 

own network resource designations and 

other usage needs. East Texas 

Cooperatives suggest that the 

Commission also require that 

transmission providers distinguish 

between denials of requests for firm and 

non-firm transmission service. 

375. Some commenters urge the 

Commission to clearly define the scope 

of any transmission service request 

information subject to the proposed 

five-year record retention requirement 

to ensure that no undue administrative 

burden is placed on transmission 

providers.213 TVA questions the need to 

extend the time period for an additional 

two years. TVA states that the benefits 

of extension are not commensurate with 

the increased costs, since it is unaware 

of any problems that have arisen with 

the current three-year timeline. Seattle 

argues on reply that the Commission 

should retain the NOPR posting 

requirements in the Final Rule because 

information on actual transmission 

congestion can be helpful instead of sole 

reliance on simulation models. 

Commission Determination 

376. As proposed in the NOPR, the 

Commission maintains the requirement 

that a transmission provider post the 

reason for a denial of service and 

extends from three years to five years 

the period for which transmission 

providers must maintain data providing 

reasons for denial of service. In general, 

commenters support the requirement for 

posting denial of service information 

and the increase in retention time to five 

years, indicating that such information 

can be helpful to customers in their 

awareness of actual transmission 

congestion, rather than relying on 

simulation models. 

377. We also adopt TAPS’ suggestion 

to expand the regulations to include 

availability of information supporting 

the disposition of a transmission 

provider’s own network resource 

designations and to make such 

information available to any eligible 

customer rather than just to that 

customer denied service. In addition, 

we clarify that a partial denial of service 

triggers the requirements as well. Such 

information is consistent with the new 

regulations established by this Final 

Rule and will help ensure that 

customers receive transmission service 

that is not unduly discriminatory. The 

development of a log of service denials, 

full or partial, will establish an ongoing 

record of service requests and 

transmission provider responses 

demonstrating the transmission 

provider’s provision of 

nondiscriminatory open access service. 

Furthermore, repeated denials of service 

over a particular path or flowgate will 

provide an indication of congestion that 

can be used in the transmission 

planning process. In addition, we agree 

with East Texas Cooperatives that 

postings of denials of service should 

indicate whether the requested service 

was firm or non-firm. 

(6) Designation and Termination of 

Network Resources 

NOPR Proposal 

378. In the NOPR, the Commission 

proposed to require the transmission 

provider and network customers to use 

the transmission provider’s OASIS to 

request designation of a new network 

resource and to terminate the 

designation of a network resource. This 

information would be posted on OASIS 

for 90 days and be available for audit for 

a five-year period. Transmission 

customers therefore would be able to 

query such requests to designate and 


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12314 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

214See 18 CFR 37.6(a)(6). 

215E.g., APPA, Exelon, PJM, TAPS, TranServ, and 

TDU Systems. 

216See paragraph 1477, where further detail on 

using OASIS to request designation of network 

resources is provided. 

terminate a network resource.214 The 

Commission also proposed to require 

the transmission provider to post on its 

OASIS a list of its current designated 

network resources and all network 

customers’ current designated network 

resources. The list would include the 

resource name, geographic and 

electrical location and amount of 

capacity of the designated network 

resource. 

Comments 

379. Several commenters support the 

Commission’s proposal to require 

transmission providers and network 

customers to use the transmission 

provider’s OASIS to request or 

terminate designation of resources, 

though some indicated that the required 

network resource information is 

currently available via OASIS.215 PJM 

supports the proposal, provided that the 

electrical location is based on an 

industry standard format and any 

standard adopted by NERC takes into 

consideration possible confidentiality 

issues when posting the geographic 

location of designated network 

resources. 

380. APPA suggests that reservations 

related to future load growth also 

should be posted so that it is clear to all 

industry participants what transmission 

capacity transmission providers are 

reserving for load growth purposes. 

Williams submits that the list of current 

designated resources needs to indicate 

whether they are for native load or 

network customers, or whether they are 

for meeting forecasted loads and system 

emergencies. 

381. TranServ supports the 

Commission’s proposal and indicates 

that NAESB is the appropriate forum for 

development of standards necessary to 

support posting the designation and 

termination of network resources. 

TranServ cautions that implementation 

will require a sufficient period of time 

after the practices and standards are 

developed and suggests that changes to 

OASIS should be timed to avoid peak 

summer and winter seasons. 

382. Exelon requests that the 

Commission clarify that transmission 

providers and network customers 

making firm off-system sales may 

terminate designation of network 

resources solely for the term of such sale 

and not for other periods of time. During 

this period of termination, the firm 

capacity is posted and made available to 

other customers. 

383. Great Northern supports the 

proposal and requests clarification that, 

when a network resource is 

‘‘undesignated,’’ ATC will not be set 

aside in anticipation that it might be 

designated again as a network resource 

in the future. Great Northern requests 

that the Commission confirm that new 

requests to designate network resources, 

regardless of the prior designation of 

those resources, are placed at the end of 

the transmission service queue. 

384. Sacramento states that the 

posting requirements for network 

resources are an unnecessary burden 

and instead recommends that the 

transmission provider should be 

required to identify resources it is 

transmitting to native load when it 

denies a request for transmission service 

from a third party. 

Commission Determination 

385. The Commission adopts the 

NOPR proposal and requires 

transmission providers and network 

customers to use OASIS to request 

designation of new network resources 

and to terminate designation of network 

resources.216 This information shall be 

posted on OASIS for 90 days and 

available for audit for a five-year period. 

Transmission customers thus shall be 

able to query requests to designate and 

terminate a network resource. This 

requirement adds valuable transparency 

without undue burden, since it is 

nothing more than maintaining a 

database of designation requests made 

and responded to electronically. The 

Commission orders public utilities, 

working through NAESB, to develop 

appropriate templates for OASIS. 

386. The requests for clarifications by 

Exelon and Great Northern will not be 

addressed in this section. These 

requests are not related to OASIS 

postings, but involve changes in tariff 

language. They are addressed in section 

V.D.6 of this Final Rule. 

(7) Posting of Unused Transfer 

Capability 

NOPR Proposal 

387. In the NOPR, the Commission 

reminded transmission providers that 

transfer capability associated with 

transmission reservations that is not 

scheduled in real time should be 

included in non-firm ATC and posted 

on OASIS. 

Comments 

388. Entegra, TANC, and TDU 

Systems emphasize the need for the 

posting of unused transfer capability. 

TDU Systems state that the requirement 

to post on OASIS all transfer capability 

associated with transmission 

reservations not scheduled in real time 

furthers not only the Commission’s 

goals with respect to comparability and 

transparency of ATC calculations, but 

also the Commission’s goals in freeing 

up access to transmission capacity for 

transmission customers. 

Commission Determination 

389. We affirm our statement in the 

NOPR proposal acknowledging that 

transfer capability associated with 

transmission reservations that are not 

scheduled in real time is required to be 

made available as non-firm, and posted 

on OASIS. 

(8) Other OASIS Issues 

Comments 

390. MidAmerican, PacifiCorp and 

Pinnacle contend that the development 

of the OASIS posting requirements is 

technical in nature and should be 

addressed by the NERC and NAESB 

processes. 

391. NRECA recommends that the 

Commission require public utility 

transmission providers to make OASIS 

data available in a useable, machinereadable and manipulable format to 

transmission customers (so they can be 

better prepared to make decisions about 

their transmission needs) and to the 

Commission (so that it can monitor the 

provision of transmission service). 

Similarly, Powerex states that posted 

data must be in sufficient detail to 

permit third parties to independently 

review and verify ATC postings and 

treatment of transmission service 

requests. 

392. Utah Municipals suggest that 

OASIS sites be as uniform and 

compatible as possible and reasonably 

user-friendly, and that certificate fees 

for access to non-public sites be 

evaluated for legitimacy. Arkansas 

Commission and Seattle also express 

concern over the OASIS access 

requirements established by most 

transmission providers, which require 

viewers to purchase certificates or 

licenses for the particular computers 

from which OASIS access is sought. 

393. Williams suggests that all 

transmission service-related business 

practices and local procedures, 

including the exercise of discretion or 

waiver or granting of exception, be 

posted on the transmission provider’s 

OASIS. It also suggests that real-time 

data and import/export limits by 

constrained area should be posted on 

OASIS, along with line outages 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12315 

217See Critical Energy Infrastructure Information, 

Order No. 683, 71 FR 58273 (Oct. 3, 2006), FERC 

Stats. & Regs. ¶ 31,228 at P 66 (2006), reh’g pending. 

We note that the Commission is proposing to 

change the definition of CEII in a proceeding in 

Docket No. RM06–23–000. See Critical Energy 

Infrastructure Information, Notice of Proposed 

Rulemaking, 71 FR 58325 (Oct. 3, 2006), FERC 

Stats. & Regs. ¶ 32,607 (2006). 

218See 18 CFR 388.112–113. 

219E.g., MidAmerican, Sacramento, Southern, 

and TVA. 

220E.g., Nevada Companies, East Texas 

Cooperatives, PJM, and TDU Systems. 

(planned and unplanned), estimated 

return to service dates and de-rates of a 

line. 

Commission Determination 

394. In response to NRECA and other 

commenters regarding the availability 

and format of data available on OASIS, 

we note that current regulations already 

require that OASIS data be made 

available in a useable, machine-readable 

user friendly format to transmission 

customers. The improvements required 

in the Final Rule will enhance the level 

of detail posted on OASIS and, in turn, 

transmission customers’ ability to verify 

the transmission provider’s treatment of 

transmission requests. Thus, to the 

extent NRECA or others desire greater 

consistency in data formats, they should 

propose such revisions through the 

NERC and NAESB processes. 

395. Regarding comments received 

expressing concern about the use of 

certificates for OASIS access, we believe 

that the use of such certificates can be 

appropriate. However, the Commission 

reminds transmission providers that the 

cost of OASIS access, whether by 

registration, certificate or other form of 

license, should be limited to a nominal 

charge, e.g., no more than $100. This 

nominal fee provides funding for OASIS 

maintenance while assuring that all 

transmission customers and potential 

customers will not be denied access 

because of excessive fees. 

396. With respect to Williams’ request 

for additional OASIS postings, we agree 

that such additional data would be 

useful to transmission customers and is 

already posted on some ISO and RTO 

Web sites and, to a lesser extent, on the 

NERC web site (TLR data). Therefore, 

we require that all transmission servicerelated business practices and local 

procedures, including waivers, should 

be posted on or made available through 

OASIS. With respect to real-time data 

and import/export limits by constrained 

area, estimated return-to-service dates 

and line de-ratings, we are confident 

that most of this data is already required 

by this Final Rule and shall be provided 

whenever TTC and ATC changes in 

value trigger the posting of a narrative 

explanation of the causes of those 

changes. Moreover, the Final Rule 

requires a broad data exchange among 

transmission providers, including 

information on line outages and other 

data relating to ATC calculations. 

Accordingly, we will not require 

additional OASIS postings for this data. 

(9) CEII 

NOPR Proposal 

397. Critical Energy Infrastructure 

Information (CEII) is information 

concerning proposed or existing critical 

infrastructure (physical and virtual) that 

(1) Relates to the production, 

generation, transportation, transmission 

or distribution of energy, (2) could be 

useful to a person in planning an attack 

on critical infrastructure, (3) is exempt 

from mandatory disclosure under the 

Freedom of Information Act, 5 U.S.C. 

552, and (4) does not simply give the 

location of the critical infrastructure.217

Access to such transmission related 

information has been restricted by the 

Commission’s CEII regulations.218

398. In the NOPR, the Commission 

recognized that the use of the existing 

CEII processes could undermine their 

goal of providing increased 

transparency to information necessary 

to evaluate the use of the transmission 

system. As a result, the Commission 

requested comment on procedures that 

could be adopted by transmission 

providers to streamline the resolution of 

CEII concerns and allow timely 

disclosure of information from the 

transmission providers to interested 

parties. 

Comments 

399. APPA and other commenters 

argue that the additional information 

disclosure requirements proposed in the 

NOPR raise substantial CEII concerns, 

and request the Commission to refine its 

CEII procedures to allow those with 

legitimate need for the information to 

obtain it on a timely basis.219 Bonneville 

would like to permit public access for 

stakeholders to review principles and 

methods used in ATC calculations, but 

only permit limited access, subject to 

background checks and non-disclosure 

agreements, to modeling data that may 

compromise infrastructure security. 

APPA suggests establishing a process for 

advance qualification for receipt of such 

information by those industry 

participants with rights to review 

information on the customer side of 

OASIS, without giving blanket public 

access. TDU Systems urge the 

Commission to adopt a streamlined 

process to ensure timely resolution of 

ATC calculation disputes and to adopt 

measures that ensure that CEII claims do 

not unduly restrict information. 

400. EEI and Southern caution that 

the release of a transmission provider’s 

explanation of methodologies, practices, 

and procedures in Attachment C may 

not give rise to CEII concerns, but that 

other information such as energy 

infrastructure data, models and 

assessments do raise security and 

confidentiality concerns. They propose 

that a transmission provider have the 

ability to seek confidential treatment of 

such information. Allegheny proposes 

that an independent third party or 

Commission staff review and explain 

ATC calculations to interested parties 

without disclosing CEII. 

401. Several commenters believe that 

much of the information the 

Commission proposes to require 

transmission providers to provide will 

not pose CEII concerns.220 However, 

Entergy states that some of the 

information requires protection as 

proprietary information because its 

public availability over OASIS would 

reveal commercially sensitive 

information. ISO New England also 

points out that information relevant to 

the ATC calculation may be marketsensitive 

402. Pinnacle believes the current 

CEII process is not unduly burdensome 

and urges the Commission to continue 

to apply the existing CEII procedures, 

which allow transmission customers 

with digital certificates or passwords to 

access publicly restricted transmission 

information. 

Commission Determination 

403. The Commission acknowledges 

that certain data and studies required to 

be made public under this Final Rule 

may contain CEII. The Commission has 

a responsibility to protect this 

information. However, the Commission 

agrees with APPA, Bonneville, and TDU 

Systems that those with a legitimate 

need for CEII information must be able 

to obtain it on a timely basis. The 

Commission also shares EEI and 

Southern’s concerns that the data, 

models and assessments used to 

calculate ATC may contain information 

that raises security and confidentiality 

concerns, and ISO New England and 

Entergy’s concerns about commercial 

and market-sensitive information. 

404. In order to provide transparency 

and avoid undue delays in providing 

information to those with a legitimate 

need for it, the Commission requires 


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221 18 CFR 388.113. 

222E.g., Arkansas Commission, Constellation, 

MidAmerican, MDEA, Morgan Stanley, Nevada 

Companies, NRECA, Suez Energy NA, and 

TranServ. 

223E.g., Ameren, Constellation, E.ON, Nevada 

Companies, NRECA, Powerex, Suez Energy NA, 

TAPS, TDU Systems, and TranServ. 

224E.g., E.ON, Entergy, LDWP, and TranServ. 

transmission providers to establish a 

standard disclosure procedure for CEII 

required to be disclosed by this Final 

Rule. We note that transmission 

customers already have digital 

certificates or passwords to access 

publicly restricted transmission 

information on OASIS. Transmission 

providers may set up an additional login 

requirement for users to view CEII 

sections of the OASIS, requiring users to 

acknowledge that they will be viewing 

CEII information. Transmission 

providers may require customers to sign 

a nondisclosure agreement at the time 

that the customer obtains access to this 

portion of the OASIS. Only information 

that meets the criteria for CEII, as 

defined in section 388.113 of the 

Commission’s regulations,221 should be 

posted in this section of the OASIS. 

Transmission providers will be 

responsible for identifying CEII and 

facilitating access to it by appropriate 

entities, and the Commission will be 

available to resolve disputes if they 

arise. 

(10) Additional Data Posting 

NOPR Proposal 

405. To further reduce discretion in 

calculating ATC/AFC, the Commission 

proposed that transmission providers 

post on OASIS metrics related to the 

provision of transmission service under 

their OATT. In the NOPR, the 

Commission proposed to require the 

monthly posting of (1) The number of 

affiliate versus non-affiliate requests for 

transmission service that have been 

rejected and (2) the number of affiliate 

versus non-affiliate requests for 

transmission service that have been 

made. This posting would also detail 

the length of service request (e.g., shortterm or long-term) and the type of 

service requested (e.g., firm point-topoint, non-firm point-to-point or 

network service). The Commission 

sought comments regarding whether it 

should require transmission providers 

to post their underlying load forecast 

assumptions for all ATC calculations 

and, on a daily basis their actual daily 

peak load for the prior day. Finally, the 

Commission asked for comment on the 

overall benefit of posting the proposed 

metrics, on potential alternative metrics, 

and on working through NAESB to 

develop standards for consistent 

methods of posting the new 

requirements on OASIS. 

Comments 

406. PJM and other commenters 

support the proposal to post data 

showing acceptances and denials of 

transmission service requests of nonaffiliates and affiliates.222 However, PJM 

and Ameren argue that the affiliate 

posting requirement should not apply to 

RTOs and ISOs, because they are 

independent, have no affiliates, and lack 

incentive to favor one transmission 

customer over another. MDEA requests 

clarification on how the additional 

posting requirements would be applied 

under Entergy’s weekly procurement 

process. Entergy notes on reply that the 

Commission has already established 

metrics to measure the performance of 

its weekly procurement process, and the 

creation of further metrics are beyond 

the scope in a generic rulemaking. 

Entergy further points out that nonaffiliated generating facilities that are 

designated as network resources to serve 

native load also benefit from 

transmission service obtained in this 

manner. It suggests that NAESB is the 

best forum for considering such issues 

and developing specific procedures for 

calculating these metrics. TranServ 

suggests that there are other useful 

metrics that NAESB should be directed 

to define, such as average time to 

evaluate requests and confirm requests, 

and percentage of requests denied, 

approved and withdrawn. 

407. PJM notes its support of 

proposed OASIS posting reforms, but 

cautions that all industry groups must 

have an equitable and proportionate 

voice in NAESB if it is requested to 

develop standards. It also expresses 

concern that PJM and other RTOs have 

established a practice of posting a 

significant amount of data for 

participants’ use in formats and 

applications which respective members 

have requested and approved through 

stakeholder processes. 

408. APPA points out that the data on 

transmission denials would be useful to 

the Department of Energy (DOE) in 

reporting on congestion in its triennial 

congestion studies to be prepared under 

FPA section 216(a), and that NAESB 

may be able to provide standard formats 

for disclosure of such data. Some APPA 

members express a preference for NERC 

to develop these standards, while others 

stress the need for regional variation in 

posting requirements. 

409. Ameren questions whether the 

posting requirement would serve the 

Commission’s objective of identifying 

undue discrimination even in cases 

where the transmission provider is not 

an RTO or other independent 

transmission provider, because the 

metrics can lead to incorrect 

impressions. MidAmerican also states 

that the proposed posting would require 

sophisticated analysis to yield useful 

benefits. 

410. EEI is not opposed to the 

proposal to post metrics on acceptance 

and denial of requests for transmission 

service, but suggests such information is 

already available on OASIS and that any 

customer or the Commission staff can 

develop its own metrics. Southern also 

states that this data is currently 

available. 

411. Several commenters support the 

posting of forecast and actual daily peak 

loads.223 Ameren states that the 

proposed requirement would produce a 

useful comparison, increase 

transparency, and provide the ability to 

verify that an appropriate amount of 

capacity is being set aside for native 

load. E.ON states that RTO and ISO 

forecasts and actual data need to be 

posted with sufficient granularity to 

allow for meaningful comparison of 

control area and LSE load levels. EEI 

requests that the Commission clarify 

that its proposal to require the posting 

of peak loads applies to system-wide 

loads and not only to the native load of 

the transmission provider. It also seeks 

clarification that the differences 

between forecast and actual system peak 

loads not result in any repercussions. 

412. APPA members in the East 

generally favor the proposal to post the 

load information, but its members in the 

West expressed concerns about the 

competitive implications of providing 

such data. Additional commenters 

express concern about data 

confidentiality.224 TAPS contends that 

providing for data disclosure on a oneday lag basis would alleviate these 

commercial concerns, but it also 

suggests that the Commission should 

require the disclosure of projected load 

forecast information on request to a 

customer’s non-market employees or 

agents. 

Commission Determination 

413. The Commission adopts the 

proposed requirement to post on OASIS 

metrics related to the provision of 

transmission service under the OATT. 

Specifically, transmission providers 

must post (1) The number of affiliate 

versus non-affiliate requests for 

transmission service that have been 

rejected and (2) the number of affiliate 

versus non-affiliate requests for 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12317 

225See Order No. 888–A at 30,311. 

226See id. 

227Pro forma OATT section 21.2, ‘‘Coordination 

of Third-Party System Additions,’’ provides for 

certain rights for transmission providers to 

coordinate construction of facilities on their 

systems associated with point-to-point customer 

requests and related construction on a third-party 

transmission system, but imposes no obligation on 

transmission providers. 

transmission service that have been 

made. This posting must detail the 

length of service request (e.g., short-term 

or long-term) and the type of service 

requested (e.g., firm point-to-point, nonfirm point-to-point or network service). 

The Commission also will require 

transmission providers to post their 

underlying load forecast assumptions 

for all ATC calculations and, to post on 

a daily basis, their actual daily peak 

load for the prior day. The Commission 

directs transmission providers to work 

through NAESB to develop standards 

for consistent methods of posting the 

new requirements on OASIS. 

414. The Commission agrees with PJM 

and Ameren that affiliate posting 

requirements do not apply to RTOs and 

ISOs, since they do not have affiliates to 

transact with. The Commission also 

agrees with Entergy that the metrics 

established for its weekly procurement 

process are outside the scope of this 

proceeding. 

415. In response to Southern’s point 

that the information necessary to 

compute the metrics is already available 

on OASIS, while it is true that service 

denial information is available on 

OASIS for long periods, request 

information is not. As such, a customer 

would need to continuously download 

information from OASIS to record the 

data sufficient to calculate the metrics 

on its own. The Commission concludes 

that it is not unduly burdensome for 

transmission providers to calculate the 

metrics required by this Final Rule. 

416. With regard to posting of load 

forecasts and actual daily peak load, we 

conclude that such postings are 

necessary to provide transparency for 

transmission customers. We agree with 

E.ON that RTO and ISO load data needs 

to be posted at a sufficient granularity 

to allow for meaningful comparison of 

control area and LSE load levels. Most 

RTOs and ISOs post load data for the 

entire footprint, but few post it on an 

LSE or control area basis. We therefore 

direct ISOs and RTOs to post load data 

for the entire ISO/RTO footprint and for 

each LSE or control area footprint 

within the ISO/RTO. This will not 

create an undue burden on ISOs and 

RTOs, since the load data for the entire 

footprint is an aggregation of load data 

across the LSEs or control areas in the 

footprint. We also agree with EEI that 

the peak load applies to system-wide 

load, including native load. We direct 

transmission providers to post load 

forecasts and actual daily peak load for 

both system-wide load (including native 

load) and native load, as this data will 

be useful to customers and regulators. 

We deny EEI’s request for a guarantee 

that transmission providers will not be 

held accountable for producing a 

reasonable load forecast. While we do 

not intend to penalize transmission 

providers for failing to account for 

unforeseen circumstances, we retain our 

ability to investigate any allegations of 

manipulation of load forecasts, as this 

could be used as a means of 

inappropriately denying requested 

transmission service. 

417. The Commission is not 

convinced by the views of some 

commenters that load data has 

competitive implications. The 

Commission notes, as PJM pointed out 

in its comments, that many RTOs have 

an established practice of posting 

significant amounts of load data for 

participants’ use, and this data posting 

has not raised competitive concerns. 

B. Coordinated, Open and Transparent 

Planning 

1. The Need for Reform 

418. Order No. 888 set forth certain 

minimum requirements for transmission 

system planning. For example, Order 

No. 888 and the pro forma OATT 

require that transmission providers plan 

and upgrade their transmission systems 

to provide comparable open access 

transmission service for their 

transmission customers. With regard to 

network service, section 28.2 of the pro 

forma OATT provides that the 

transmission provider ‘‘will plan, 

construct, operate and maintain its 

Transmission System in accordance 

with Good Utility Practice in order to 

provide the Network Customer with 

Network Integration Transmission 

Service over the Transmission 

Provider’s Transmission System.’’

Section 28.2 also provides that the 

Transmission Provider shall, consistent 

with Good Utility Practice, ‘‘endeavor to 

construct and place into service 

sufficient transfer capability to deliver 

the Network Customer’s Network 

Resources to serve its Network Load on 

a basis comparable to the Transmission 

Provider’s delivery of its own generating 

and purchased resources to its Native 

Load Customers.’’

419. The pro forma OATT also 

requires that new facilities be 

constructed to meet the service requests 

of long-term firm point-to-point 

customers. Section 13.5 of the pro forma 

OATT requires the transmission 

provider to consider redispatch of the 

system to relieve any constraints that 

are inhibiting a transmission customer’s 

point-to-point service if it is economical 

to do so; but if redispatch is not 

economical, the transmission provider 

is obligated to expand or upgrade its 

system. This expansion obligation on 

the part of the transmission provider for 

point-to-point service is found in 

section 15.4 of the pro forma OATT, 

which provides that, when a 

transmission provider cannot 

accommodate a request for point-topoint transmission because of 

insufficient capability on its system, it 

will ‘‘use due diligence to expand or 

modify its Transmission System to 

provide the requested Firm 

Transmission Service.’’ Section 15.4 

goes on to provide that ‘‘the 

Transmission Provider will conform to 

Good Utility Practice in determining the 

need for new facilities and in the design 

and construction of such facilities.’’ The 

transmission provider’s obligation to 

upgrade or expand its system to provide 

point-to-point service as detailed in 

section 15.4 is contingent on the 

transmission customer agreeing to 

compensate the transmission provider 

for such costs pursuant to the terms of 

section 27 (providing for cost 

responsibility for upgrades and/or 

redispatch ‘‘to the extent consistent 

with Commission policy’’). 

420. In Order No. 888–A, the 

Commission encouraged utilities to 

engage in joint planning with other 

utilities and customers and to allow 

affected customers to participate in 

facilities studies to the extent 

practicable. The Commission also 

encouraged regional planning so that 

the needs of all participants are 

represented in the planning process.225

Order No. 888–A did not, however, 

require that transmission providers 

coordinate with either their network or 

point-to-point customers in 

transmission planning or otherwise 

publish the criteria, assumptions, or 

data underlying their transmission 

plans. The Commission also did not 

require joint planning between 

transmission providers and their 

customers or between transmission 

providers in a given region.226 The only 

section of the existing pro forma OATT 

that directly speaks to joint planning is 

section 30.9, which provides that a 

network customer must receive credit 

when facilities constructed by the 

customer are jointly planned and 

installed in coordination with the 

transmission provider.227


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12318 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

228The number of TLRs has increased 

significantly since NERC started reporting annual 

statistics. The total number of TLRs each year has 

grown from under 500 in 1998 and 1999 to around 

2000 over the last four years from 2002 to 2006. The 

number of TLR actions at the highest levels, 

requiring curtailment of firm transmission flows, 

has also grown, from under 10 before 2001 to 70 

in 2006, averaging 55 per year from 2003 to 2006. 

Source: NERC Web site, ftp://www.nerc.com/pub/ 

sys/all_updl/oc/scs/logs/trends.htm. In addition, 

congestion costs continue to be a major issue in 

RTO markets. For example, congestion costs in PJM 

were $2.09 billion in calendar year 2005, which was 

a 179 percent increase over 2004. Although this 

increase resulted primarily from increases in PJM 

annual billings, the congestion costs in both years 

were approximately 9 percent of total PJM billings 

in both years and have ranged from 6 percent to 10 

percent of total billings since 2000. Source: 2005 

PJM State of the Markets Report, April 2006. 

229Order No. 888 at 31,682. 

230 225 F.3d at 684. 

231 535 U.S. at 8–9 (citation and footnotes 

omitted). 

232As discussed in more detail in the NOPR, the 

need for reform was recognized by the Consumer 

Energy Council of America (CECA), a public 

interest energy policy organization with a 30-year 

history of bringing stakeholders together to find 

solutions to contentious energy policy issues. CECA 

launched its Transmission Infrastructure Forum in 

early 2004, which published its conclusions in 

January 2005 in a final report titled ‘‘Keeping the 

Power Flowing: Ensuring a Strong Transmission 

System to Support Consumer Needs for CostEffectiveness, Security and Reliability’’ (CECA 

Report). Among other things, the CECA Report 

concludes that regional transmission planning with 

consumer input early in the process is needed to 

ensure the development of a robust transmission 

system capable of meeting consumer needs reliably 

and at reasonable cost over time. The CECA Report 

stresses that regional transmission planning must 

address inter-regional coordination, the need for 

both reliability and economic upgrades to the 

system, and critical infrastructure to support 

national security and environmental concerns. See 

NOPR at P 207. 

233 In our discussion of enforcement issues at 

section V.E of this Final Rule, we note specific 

situations in which transmission providers have 

agreed to resolve staff allegations that they engaged 

in OATT violations involving transactions with 

affiliates. While these specific situations may not 

directly relate to discrimination in planning, they 

nevertheless document the continuing incentive of 

transmission providers to favor themselves and 

their affiliates in the provision of transmission 

service. 

234See Order No. 888 at 31,669 (noting that the 

FPA ‘‘fairly bristles’’ with concern for undue 

discrimination (citing AGD, 824 F.2d at 998). 

421. As the Commission stated in the 

NOPR, the Nation has witnessed a 

decline in transmission investment 

relative to load growth in the ten years 

since Order No. 888 was issued. 

Transmission capacity per MW of peak 

demand has declined in every NERC 

region. Transmission constraints plague 

most regions of the country, as reflected 

in the limited amounts of ATC posted 

in many regions, increased frequency of 

denied transmission requests, 

increasingly common transmission 

service interruptions or curtailments 

and rising congestion costs in organized 

markets.228

422. We do not believe that the 

existing pro forma OATT is sufficient in 

an era of increasing transmission 

congestion and the need for significant 

new transmission investment. We 

cannot rely on the self-interest of 

transmission providers to expand the 

grid in a nondiscriminatory manner. 

Although many transmission providers 

have an incentive to expand the grid to 

meet their State-imposed obligations to 

serve, they can have a disincentive to 

remedy transmission congestion when 

doing so reduces the value of their 

generation or otherwise stimulates new 

entry or greater competition in their 

area. For example, a transmission 

provider does not have an incentive to 

relieve local congestion that restricts the 

output of a competing merchant 

generator if doing so will make the 

transmission provider’s own generation 

less competitive. A transmission 

provider also does not have an incentive 

to increase the import or export capacity 

of its transmission system if doing so 

would allow cheaper power to displace 

its higher cost generation or otherwise 

make new entry more profitable by 

facilitating exports. 

423. As the Commission explained in 

Order No. 888, ‘‘[i]t is in the economic 

self-interest of transmission 

monopolists, particularly those with 

high-cost generation assets, to deny 

transmission or to offer transmission on 

a basis that is inferior to that which they 

provide themselves.’’ 229 The court 

agreed on review of Order No. 888, 

noting in TAPS v. FERC that ‘‘[u]tilities 

that own or control transmission 

facilities naturally wish to maximize 

profit. The transmission-owning utilities 

thus can be expected to act in their own 

interest to maintain their monopoly and 

to use that position to retain or expand 

the market share for their own generated 

electricity, even if they do so at the 

expense of lower-cost generation 

companies and consumers.’’ 230 The 

Supreme Court in New York v. FERC 

similarly explained that ‘‘public utilities 

retain ownership of the transmission 

lines that must be used by their 

competitors to deliver electric energy to 

wholesale and retail customers. The 

utilities’ control of transmission 

facilities gives them the power either to 

refuse to deliver energy produced by 

competitors or to deliver competitors’

power on terms and conditions less 

favorable than those they apply to their 

own transmissions.’’ 231

424. The existing pro forma OATT 

does not counteract these incentives in 

the planning area because there are no 

clear criteria regarding the transmission 

provider’s planning obligation. 

Although the pro forma OATT contains 

a general obligation to plan for the 

needs of their network customers and to 

expand their systems to provide service 

to point-to-point customers, there is no 

requirement that the overall 

transmission planning process be open 

to customers, competitors, and State 

commissions.232 Rather, transmission 

providers may develop transmission 

plans with limited or no input from 

customers or other stakeholders. There 

also is no requirement that the key 

assumptions and data that underlie 

transmission plans be made available to 

customers. 

425. Taken together, this lack of 

coordination, openness, and 

transparency results in opportunities for 

undue discrimination in transmission 

planning. Without adequate 

coordination and open participation, 

market participants have no means to 

determine whether the plan developed 

by the transmission provider in 

isolation is unduly discriminatory. This 

means that disputes over access and 

discrimination occur primarily after-thefact because there is insufficient 

coordination and transparency between 

transmission providers and their 

customers for purposes of planning.233

The Commission has a duty to prevent 

undue discrimination in the rates, 

terms, and conditions of public utility 

transmission service and, therefore, an 

obligation to remedy these transmission 

planning deficiencies. As we explain 

above, our authority to remedy undue 

discrimination is broad.234 In addition, 

new section 217 of the FPA requires the 

Commission to exercise its jurisdiction 

in a manner that facilitates the planning 

and expansion of transmission facilities 

to meet the reasonable needs of LSEs. A 

more transparent and coordinated 

regional planning process will further 

these priorities, as well as support the 

DOE’s responsibilities under EPAct 

2005 section 1221 to study transmission 

congestion and issue reports designating 

National Interest Electric Transmission 

Corridors and the Commission’s 

responsibilities under EPAct 2005 

section 1223. 

NOPR Proposal 

426. In order to provide for more 

comparable open access transmission 

service, limit the potential for undue 

discrimination and anticompetitive 

conduct, and satisfy its statutory 

responsibilities under section 217 of the 

FPA, the Commission proposed to 

amend the pro forma OATT to require 

coordinated, open, and transparent 

transmission planning on both a local 

and regional level. Each public utility 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12319 

235The one exception is the congestion studies 

requirement, which is generally opposed by 

transmission providers and supported by 

customers. 

236E.g., Duke, Exelon, and Xcel. 

237E.g., Indicated Parties Reply, Old Dominion, 

NRECA, and TAPS. 

238See, e.g., Duke and Southern. 239See, e.g., APPA and EPSA. However, NRG and 

Reliant believe that the planning process outside of 

RTOs is fundamentally flawed and cannot be 

remedied by the NOPR’s planning proposal. 240Progress Energy also claims that the 

Commission does not have any jurisdiction to 

mandate regional planning. 241See also TAPS Reply. 242See, e.g., Nevada Companies, New Mexico 

Attorney General, North Carolina Commission 

Reply, and Southern. 

transmission provider would be 

required to submit, as part of its 

compliance filing in this proceeding, a 

proposal for a coordinated and regional 

planning process that complies with the 

following eight planning principles: 

Coordination, openness, transparency, 

information exchange, comparability, 

dispute resolution, regional 

participation, and congestion studies. In 

the alternative, transmission providers 

could make a compliance filing in this 

proceeding describing their existing 

coordinated and regional planning 

processes and showing that they are 

consistent with or superior to that 

required in the Final Rule. 

427. The Commission stated that it 

expected non-public utility 

transmission providers to participate in 

the proposed planning processes, given 

that effective regional planning cannot 

occur without the participation of all 

transmission providers, owners, and 

customers. Although the Commission 

encouraged the use of an independent 

third party to oversee or coordinate the 

planning process, the NOPR did not 

propose to require it. The Commission 

also strongly encouraged the 

participation of State commissions and 

other State agencies in planning 

activities. 

428. The Commission sought 

comment on several aspects of the 

NOPR proposal. First, the Commission 

inquired as to the level of flexibility 

each transmission provider should be 

given in implementing any principles 

adopted. Second, the Commission 

sought comment, by way of example, on 

transmission planning processes that 

comply with the NOPR reforms in 

principle. Third, the Commission 

sought comment on whether there are 

other principles or requirements that 

should be adopted to support the 

construction of needed new 

infrastructure and otherwise ensure that 

all market participants are treated on a 

comparable basis. Specifically, the 

Commission inquired: (a) Whether there 

should be a principle or guideline to 

govern the recovery and allocation of 

costs associated with funding the 

regional planning requirement; (b) 

whether there should be a requirement 

that, at least for large new transmission 

projects, there be an open season to 

allow market participants to participate 

in joint ownership of these projects; (c) 

whether there should be a specific study 

process to identify opportunities to 

enhance the grid for purposes beyond 

maintaining reliability or reducing 

current congestion; and, (d) whether 

public utilities should be required to 

develop cost allocation principles to 

address the sharing of the costs of new 

transmission projects and, given that 

such projects can take years to 

construct, whether the planning process 

should be required to look out at least 

as far as the longest time it would take 

to build such an upgrade in the region 

in question. Finally, the Commission 

sought comment on the level of detail to 

be required in transmission providers’

OATTs. 

Comments 

429. Most commenters support the 

development of coordinated, open, and 

transparent planning. While differing on 

how they should be implemented, 

commenters express broad support for 

the eight planning principles,235 though 

all RTOs and ISOs and many investorowned utilities believe that their 

planning processes already comply with 

the proposals in the NOPR. ISO/RTO 

Council, as well as individual RTOs and 

ISOs, advance the position that RTOs 

and ISOs already meet the planning 

requirements in the NOPR, that there 

has been no credible case made for 

reopening their already approved 

planning processes, and that RTOs and 

ISOs should be exempt from complying 

with the NOPR’s planning principles. 

430. Some transmission providers 

agree that RTOs already meet the 

principles, and others argue against 

commenters who maintain that RTOs 

‘‘rubber stamp’’ transmission provider 

plans.236 For example, MISO asserts that 

it conducts an open planning process 

and does not ‘‘rubber stamp’’ projects. 

Duke concurs with MISO, stating that 

there are abundant opportunities for 

participation in the MISO planning 

process. Xcel also replies in support of 

the MISO process. 

431. Several transmission customers, 

however, argue that current RTO 

processes are insufficient because, 

among other things, they merely accept 

the transmission owners’ plans and only 

provide for after-the-fact input, thus 

failing to satisfy the planning principles 

proposed in the NOPR.237 Old 

Dominion also asserts that RTOs 

generally approve transmission owner 

identified upgrades, which give them 

the advantage of having their own 

parochial plans incorporated into the 

regional plan without any separate 

evaluation or complete stakeholder 

input. TAPS asserts that open planning 

should apply both to the RTO and the 

underlying transmission owners’

planning efforts. In its reply, WPS 

opposes MISO’s proposal to be exempt 

from the NOPR’s planning 

requirements, arguing that the MISO 

process is not open and only aggregates 

the plans of the transmission providers. 

432. EEI takes issue with broad 

statements in the NOPR that assert that 

transmission providers have a 

disincentive to remedy transmission 

congestion and to plan their 

transmission systems on a comparable 

basis. Other individual investor-owned 

utilities also assert that the record does 

not support the NOPR’s claims that a 

mandatory coordinated, open, and 

transparent planning process is 

necessary to remedy undue 

discrimination.238 Many others, 

however, believe the NOPR correctly 

diagnoses the problem of 

discrimination.239

433. Most commenters do not 

question the Commission’s jurisdiction 

to address the transmission planning 

process generally. Southern, however, 

argues that the Commission has no 

general authority in this area and that 

section 217 of the FPA does not grant 

the Commission any additional 

jurisdiction to impose a regional 

planning requirement.240 FMPA 

counters that the Commission has FPA 

authority to cure undue discrimination 

and to ensure ‘‘just and reasonable’’

transmission rates and terms by 

adopting transmission planning 

criteria.241 In their replies, APPA and 

TAPS agree with the Commission that 

FPA section 217(b)(4) can be cited as 

legal support for transmission planning. 

In its reply, NRECA stresses that the 

transmission planning process must 

focus, consistent with FPA section 

217(b)(4), on the reasonable long-term 

needs of LSEs, not all users of the 

system as argued by EPSA and NRG. 

Santee Cooper urges the Commission to 

be mindful of the limits of its 

jurisdiction in establishing study 

requirements that may delve into 

generation resource adequacy or issues 

related to the mix of generation. Other 

commenters urge the Commission not to 

impinge on State jurisdiction.242 In its 

reply, LPPC emphasizes that the 

Commission’s expectation that public 

power entities will participate is 


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243Other jurisdictional arguments primarily relate 

to the question of joint ownership, in which some 

commenters argue that the Commission lacks 

jurisdiction to mandate joint ownership 

arrangements. See, e.g., Duke, EEI, National Grid, 

Northeast Utilities, PSEG, and Southern. FMPA and 

others, however, argue that the Commission does 

have the authority to order joint ownership. Joint 

ownership will be discussed more fully below. 

244See AGD, 824 F.2d at 1008 (Commission has 

broad discretion to promulgate generic rules to 

eliminate undue discrimination without 

‘‘conduct[ing] experiments in order to rely on the 

prediction that an unsupported stone will fall’’). 

245FPA section 217(b)(4) provides that ‘‘[t]he 

Commission shall exercise the authority of the 

Commission under [the FPA] in a manner that 

facilitates the planning and expansion of 

transmission facilities to meet the reasonable needs 

of load-serving entities to satisfy the service 

obligations of the load-serving entities, and enables 

load-serving entities to secure firm transmission 

rights (or equivalent tradable or financial rights) on 

a long term basis for long term power supply 

arrangements made, or planned, to meet such 

needs.’’

246The pro forma OATT, as modified by this 

Final Rule, reflects the proposed planning 

requirement in sections 15.4, 16.1, 17.2(x), 28.2, 

29.2, 31.6. The planning process itself will be 

included as Attachment K to the pro forma OATT. 

We understand that some transmission providers 

may already have attachments to their OATTs 

labeled with the letter ‘‘K,’’ in which case 

transmission providers are free to label their 

planning process OATT attachment with the next 

available letter. 

sufficient and asserts that there is no 

reason to take further action that might 

test the limits of jurisdiction under FPA 

section 211A.243

434. WIRES endorses several planning 

objectives it believes to be critical to 

successful planning. These objectives 

include open and transparent planning 

procedures, a long-term planning 

horizon, broad-based inclusion of 

reliability, economic, efficiency and 

environmental considerations in 

planning, clear conditions under which 

a transmission owner will commit to 

build planned facilities, and provision 

for fair and efficient allocation of the 

costs of planned facilities. WIRES also 

emphasizes the importance of 

considering non-transmission 

alternatives, arguing that an appropriate 

grid plan must be based on an integrated 

view of all alternatives, including 

demand response and distributed 

generation. 

Commission Determination 

435. In order to limit the 

opportunities for undue discrimination 

described above and in the NOPR, and 

to ensure that comparable transmission 

service is provided by all public utility 

transmission providers, including RTOs 

and ISOs, the Commission concludes 

that it is necessary to amend the existing 

pro forma OATT to require coordinated, 

open, and transparent transmission 

planning on both a local and regional 

level. We disagree with commenters 

arguing either that we lack jurisdiction 

to require coordinated transmission 

planning or that we have not established 

a basis for such a requirement. The 

Commission has broad authority to 

remedy undue discrimination by 

ensuring that transmission providers 

plan for the needs of their customers on 

a comparable basis.244 That 

fundamental requirement was adopted 

in Order No. 888 and the reforms 

adopted herein should ensure that it 

will be implemented properly. Further, 

we explained in detail above why 

undue discrimination remains a concern 

in the planning area and why the 

existing OATT is insufficient to address 

that concern. 

436. New section 217 of the FPA 

further supports reform in this area, as 

it reflects Congress’ intent that the 

Commission utilize its powers to 

facilitate the planning and expansion of 

the transmission system.245 Through 

EPAct 2005 sec. 1223, Congress also 

directed the Commission to encourage 

the deployment of advanced 

transmission technologies in 

infrastructure improvements, including 

among others optimized transmission 

line configurations (including multiple 

phased transmission lines), controllable 

load, distributed generation (including 

PV, fuel cells, and microturbines), and 

enhanced power device monitoring. 

437. Accordingly, each public utility 

transmission provider is required to 

submit, as part of a compliance filing in 

this proceeding, a proposal for a 

coordinated and regional planning 

process that complies with the planning 

principles and other requirements in 

this Final Rule.246 In the alternative, a 

transmission provider (including an 

RTO or an ISO, as discussed below), 

may make a compliance filing in this 

proceeding describing its existing 

coordinated and regional planning 

process, including the appropriate 

language in its tariff, and show that this 

existing process is consistent with or 

superior to the requirements in this 

Final Rule. Under either of these 

approaches, the process must be 

documented as an attachment to the 

transmission provider’s OATT. 

438. At the outset, we note that the 

planning obligations imposed in this 

Final Rule do not address or dictate 

which investments identified in a 

transmission plan should be undertaken 

by transmission providers. Furthermore, 

except for the discussion below of cost 

allocation for transmission investments 

under Principle 9, the planning 

obligations included in this Final Rule 

do not address whether or how 

investments identified in a transmission 

plan should be compensated. Through 

the principles described below, we 

establish a process through which 

transmission providers must coordinate 

with customers, neighboring 

transmission providers, affected State 

authorities, and other stakeholders in 

order to ensure that transmission plans 

are not developed in an unduly 

discriminatory manner. 

439. As for the application of the 

Final Rule’s coordinated planning 

requirement to RTOs and ISOs, which 

already have a Commission-approved 

transmission planning process on file 

with us, we note that the intent of our 

reform in this Final Rule is not to 

reopen prior approvals, but rather to 

ensure that the transmission planning 

process utilized by each RTO and ISO 

is consistent with or superior to the 

planning process adopted here. When 

the Commission approved the existing 

RTO and ISO transmission planning 

processes, they were found to be 

consistent with or superior to the 

existing pro forma OATT. Because the 

pro forma OATT is being reformed by 

this Final Rule, it is necessary for each 

RTO and ISO to now either reform its 

process or show that its planning 

process is consistent with or superior to 

the pro forma OATT, as modified by the 

Final Rule. 

440. We also make clear that 

transmission owning members of ISOs 

and RTOs must participate in the 

planning processes adopted in this Final 

Rule. In order for an RTO’s or ISO’s 

planning process to be open and 

transparent, transmission customers and 

stakeholders must be able to participate 

in each underlying transmission 

owner’s planning process. This is 

important because, in many cases, RTO 

planning processes may focus 

principally on regional problems and 

solutions, not local planning issues that 

may be addressed by individual 

transmission owners. These local 

planning issues, however, may be 

critically important to transmission 

customers, such as those embedded 

within the service areas of individual 

transmission owners. Consequently, the 

intent of the Final Rule will not be 

realized if only the regional planning 

process conducted by the RTOs and 

ISOs is shown to be consistent with or 

superior to the Final Rule. To ensure 

full compliance, individual 

transmission owners must, to the extent 

that they perform transmission planning 

within an RTO or ISO, comply with the 

Final Rule as well. Without such a 

requirement, the more regional RTO or 


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247We understand that there are some 

transmission owners in RTOs or ISOs that continue 

to have OATTs on file under which they provide 

service over certain transmission facilities that they 

did not turn over to the operational control of the 

RTO or ISO. Like any other transmission provider, 

those entities must submit a compliance filing to 

their OATTs that satisfies all requirements of this 

Final Rule, including the inclusion of an 

attachment governing their own planning 

procedures. As we explain elsewhere, the 

compliance filing deadline for transmission owning 

participants in RTOs and ISOs shall be the same as 

the RTO and ISO deadline, i.e., 210 days after 

publication of the Final Rule in the Federal 

Register. 

248FPA section 211A(b) provides, in pertinent 

part, that ‘‘the Commission may, by rule or order, 

require an unregulated transmitting utility to 

provide transmission services—(1) At rates that are 

comparable to those that the unregulated 

transmitting utility charges itself; and (2) on terms 

and conditions (not relating to rates) that are 

comparable to those under which the unregulated 

transmitting utility provides transmission services 

to itself and that are not unduly discriminatory or 

preferential.’’ The non-public utility transmission 

providers referred to in this Final Rule include 

unregulated transmitting utilities that are subject to 

FPA section 211A. 

249E.g., Allegheny, Duke, EEI, International 

Transmission, MidAmerican, NorthWestern, and 

SCE. 

250E.g., Allegheny, APPA, Bonneville, California 

Commission, Duke, Entergy, Imperial, International 

Transmission, MidAmerican, NCEMC, NC 

Transmission Planning Participants Reply, 

NorthWestern, NRECA, Pinnacle, Progress Energy, 

CREPC, Santee Cooper, SCE, TVA, and WAPA. 

ISO planning process will not comply 

with the requirements of the Final Rule 

to the extent they incorporate and rely 

on information prepared by underlying 

transmission owners that, in turn, have 

not complied with the Final Rule. 

Accordingly, as part of their compliance 

filings in this proceeding, RTOs and 

ISOs must indicate how all participating 

transmission owners within their 

footprint will comply with the planning 

requirements of this Final Rule. While 

we leave the mechanics of such 

compliance to each RTO and ISO, we 

emphasize that the RTO’s or ISO’s 

planning processes will be insufficient 

if its underlying transmission owners 

are not also obligated to engage in 

transmission planning that complies 

with Final Rule.247

441. The Commission also expects all 

non-public utility transmission 

providers to participate in the planning 

processes required by this Final Rule. A 

coordinated, open, and transparent 

regional planning process cannot 

succeed unless all transmission owners 

participate. We are encouraged, based 

on the representations of LPPC and 

others, that non-public utility 

transmission providers will fully 

participate in such processes. We 

therefore do not believe it is necessary 

at this time to invoke our authority 

under FPA section 211A, which gives us 

authority to require non-public utility 

transmission providers to provide 

transmission services on a comparable 

and not unduly discriminatory or 

preferential basis.248 If we find on the 

appropriate record, however, that nonpublic utility transmission providers are 

not participating in the planning 

processes required by this Final Rule, 

the Commission may exercise its 

authority under section 211A on a caseby-case basis. Further, we note that 

reciprocity dictates that non-public 

utility transmission providers that take 

advantage of open access due to 

improved planning should be subject to 

the same requirements as jurisdictional 

transmission providers. 

442. In sum, each OATT planning 

process attachment must incorporate the 

transmission planning principles and 

concepts in this Final Rule and must be 

filed with the Commission within 210 

days after the publication of the Final 

Rule in the Federal Register. 

Alternatively, RTOs, ISOs, and other 

transmission providers that currently 

have planning processes they believe 

comply with the Final Rule may make 

a filing with the Commission 

documenting those processes in an 

OATT attachment and explaining how 

their planning processes are consistent 

with or superior to the planning process 

adopted here. Such filings must also be 

submitted within 210 days after the 

publication of the Final Rule in the 

Federal Register. 

443. In order to assist transmission 

providers in complying with the Final 

Rule, and ensure that the planning 

procedures are developed with 

customer and stakeholder participation, 

the Commission will convene staff 

technical conferences in several broad 

regions around the country to discuss 

regional implementation and other 

compliance issues in advance of the 

compliance date. We extend an 

invitation to State regulatory 

commissions to participate in these 

technical conferences with our staff in 

order to ensure that State concerns are 

fully addressed. The Commission will 

endeavor to hold the technical 

conferences 90 to 120 days after the 

publication of the Final Rule in the 

Federal Register. To facilitate these 

conferences, each transmission provider 

should, within 75 days after the 

publication of the Final Rule in the 

Federal Register, post a ‘‘strawman’’

proposal for compliance with each of 

the planning principles adopted in the 

Final Rule, including a specification of 

the broader region in which it will 

conduct coordinated regional planning. 

This strawman may be posted on the 

transmission provider’s OASIS, or its 

Web site if it does not have its own 

OASIS (e.g., in the case of a 

transmission owning member of an RTO 

or ISO that does not have its own 

OATT). We strongly urge transmission 

providers to consult with their 

stakeholders in the development of this 

strawman. 

2. Planning Principles 

444. We set forth below the planning 

principles that must be satisfied for a 

transmission provider’s planning 

process to be considered compliant with 

the Final Rule. The NOPR identified 

eight such principles, but based on the 

comments received the Commission 

will require compliance with nine—the 

original eight plus a cost allocation 

principle, as described further below. 

a. Coordination 

445. In the NOPR, the Commission 

proposed that transmission providers 

must meet with all of their transmission 

customers and interconnected neighbors 

to develop a transmission plan on a 

nondiscriminatory basis. We sought 

comment on specific requirements for 

this coordination, such as the minimum 

number of meetings to be required each 

year, the scope of the meetings, the 

notice requirements, the format, and any 

other features deemed important by 

commenters. 

Comments 

446. Commenters express universal 

support for the general concept of 

coordination, but differ on how specific 

the requirement should be. Several 

commenters argue that the requirement 

that transmission providers ‘‘must 

meet’’ with customers and utilities is 

unrealistic.249 EEI requests that the 

Commission clarify that transmission 

providers will be responsible for 

coordinating with customers and 

holding meetings, but that the 

requirement to meet should be limited 

to making reasonable efforts to meet 

with all customers. NRECA asks on 

reply that the Commission make clear 

that the lack of full participation by 

some nonjurisdictional utilities that take 

network service under the OATT should 

not excuse the transmission provider’s 

obligation to engage in transmission 

planning. NRECA states that inclusion 

in the planning process must be an 

opportunity for LSEs, not an obligation. 

447. Other commenters express a 

more general concern that the 

Commission not be prescriptive with 

respect to meeting requirements.250 For 

example, most commenters generally 

believe the Commission should not 

prescribe rigid rules regarding the 

number of meetings that must be held 


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251E.g., Nevada Companies and NorthWestern. 

252E.g., Entergy, Progress Energy, SCE, and 

Southern. 

253E.g., NRECA, Seminole Reply, TAPS, and TDU 

Systems. 

254This collaborative approach is also generally 

supported by East Texas Cooperatives, FMPA, 

NCEMC, NCPA, and Old Dominion. NCEMC 

believes that the key to ensuring true collaboration 

is a voting structure, like that adopted in the North 

Carolina Transmission Planning Collaborative, 

which gives all load-serving entities an equal say 

in planning decisions. APPA also believes that 

giving customers a say in the outcome (e.g., through 

voting) is critical. 

each year. Xcel, however, suggests that 

a minimum of three meetings a year 

would be appropriate. Progress notes 

that coordination in North Carolina 

already occurs as a result of regular 

meetings throughout the year. Nevada 

Companies believe that meetings should 

be dependent on need and should not 

be programmatically established. TDU 

Systems recommend at least monthly 

meetings, but stress that meetings 

should be as frequent as is required to 

specify and perform the studies forming 

the basis for the plan. NCPA believes 

that the minimum requirements are not 

as important as how they can be 

monitored or enforced to ensure that 

true participation indeed occurs. 

448. Seattle suggests 30 days notice 

for meetings and that information 

regarding meetings be posted at least 

one week in advance. Entergy finds a 

notice requirement reasonable, and 

other utilities suggest a 30-day 

requirement would be appropriate.251

Seattle also suggests e-mail notification 

and Salt River supports internet posting. 

With respect to details beyond 

frequency and notice, Entergy cautions 

the Commission against being too 

prescriptive. 

449. On meeting scope, several 

commenters request that the 

Commission make clear that the 

purpose of the meeting is to focus on 

transmission issues and not provide a 

broad forum for other issues.252

Sacramento believes that meetings 

should be limited to sub-regional or 

regional transmission planning and not 

include planning to meet local 

transmission needs. 

450. Other commenters stress that 

joint planning requires more than just 

meeting with customers and that all 

LSEs need to be integrated into the 

planning process so that they are 

actively developing transmission plans 

alongside transmission providers from 

the inception.253 This concept of 

collaborative planning is a running 

theme in the comments provided by 

several public power entities, such as 

NRECA, TAPS, and TDU Systems. TDU 

Systems argue that comparability 

requires that LSEs have equal weight in 

decision-making rather than provide de 

facto veto authority to transmission 

providers. NRECA argues in its reply 

that collaborative planning is required 

by FPA section 217(b)(4). These 

commenters assert that LSEs must be 

able to participate in the development of 

planning models, including the 

assumptions and criteria that go into 

these models, and in the development of 

the base case and change case for study 

purposes, particularly as to the 

identification and projection of loads 

and resources.254 Progress and 

Southern, however, argue in replies that 

giving customers equal weight in 

decision-making crosses the line from 

planning to control by third parties, and 

Southern believes this would be 

opposed by State regulators. 

Commission Determination 

451. The Commission adopts the 

coordination principle proposed in the 

NOPR. Commenters overwhelmingly 

desire flexibility as to the coordination 

principle, and as such, we will not 

prescribe the requirements for 

coordination, such as the minimum 

number of meetings to be required each 

year, the scope of the meetings, the 

notice requirements, the format, and any 

other features. We will allow 

transmission providers, with the input 

of their customers and other 

stakeholders, to craft coordination 

requirements that work for those 

transmission providers and their 

customers and other stakeholders. 

452. We emphasize that the purpose 

of the coordination requirement is to 

eliminate the potential for undue 

discrimination in planning by opening 

appropriate lines of communication 

between transmission providers, their 

transmission-providing neighbors, 

affected State authorities, customers, 

and other stakeholders. Rigid and 

formal meeting procedures may be one 

way to accomplish this goal, but there 

may be other ways as well. For example, 

a transmission provider could meet this 

requirement by facilitating the 

formation of a permanent planning 

committee made up of itself, its 

neighboring transmission providers, 

affected State authorities, customers, 

and other stakeholders. Such a planning 

committee could develop its own means 

of communication, which may or may 

not emphasize formal meeting 

procedures. We are more concerned 

with the substance of coordination than 

its form. 

453. In response to the concerns of 

some commenters, we clarify that 

transmission providers are not required 

to meet with customers and other 

stakeholders that choose not to meet. 

Transmission providers cannot force 

others to meet with them. Transmission 

providers are, however, required to craft 

a process that allows for a reasonable 

and meaningful opportunity to meet or 

otherwise interact meaningfully. We 

also clarify that the coordination 

requirements imposed in this Final Rule 

are intended to address transmission 

planning issues, and are not intended to 

provide a forum for ancillary issues, 

such as specific siting concerns, which 

are better addressed elsewhere. As for 

NRECA’s concern that transmission 

providers must plan for their 

nonjurisdictional network customers 

even if they decline to fully participate 

in the planning process, a transmission 

provider cannot be expected to 

effectively plan for a customer if that 

customer declines to engage in the 

planning process. Therefore, we 

encourage NRECA and non-public 

utilities to participate fully in the 

planning process. 

454. In response to the suggestion by 

some commenters that we require 

transmission providers to allow 

customers to collaboratively develop 

transmission plans with transmission 

providers on a co-equal basis, we clarify 

that transmission planning is the tariff 

obligation of each transmission 

provider, and the pro forma OATT 

planning process adopted in this Final 

Rule is the means to see that it is carried 

out in a coordinated, open, and 

transparent manner, in order to ensure 

that customers are treated comparably. 

Therefore, the ultimate responsibility 

for planning remains with transmission 

providers. With this said, we fully 

intend that the planning process 

adopted herein provide for the timely 

and meaningful input and participation 

of customers into the development of 

transmission plans. This means that 

customers must be included at the early 

stages of the development of the 

transmission plan and not merely given 

an opportunity to comment on 

transmission plans that were developed 

in the first instance without their input. 

b. Openness 

455. In the NOPR, the Commission 

proposed that transmission planning 

meetings must be open to all affected 

parties (including all transmission and 

interconnection customers and State 

authorities). The Commission also 

sought comment on whether there are 

any circumstances under which 

participation should be limited, for 

example, to address confidentiality 

concerns. 


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255E.g., APPA, EEI, Salt River, and Southern. 256Other commenters also recognize the need to 

maintain confidentiality for CEII and commerciallysensitive information. E.g., Arkansas Commission, 

AWEA, California Commission, NCPA, NRECA, 

CREPC, Seattle, TDU Systems, and WAPA. 257Commenters raise issues with regard to the 

application of the Commission’s Standards of 

Conduct to planning participants in their comments 

addressing some of the other principles as well, 

which will be discussed below, as well as 

addressed in the pending rulemaking in Docket No. 

RM07–1–000. See Standards of Conduct NOPR. 

258See also East Texas Cooperatives Reply and 

NRECA Reply. 

259E.g., CAISO, EEI, and SCE. 

260E.g., APPA, California Commission, NCPA, 

CREPC, Salt River, and WAPA. Old Dominion, 

however, does not believe that any of the data 

required to be disclosed is commercially-sensitive; 

however, it does recognize that it may be CEII, in 

which case it claims security can be maintained via 

a secure OASIS site. 

Comments 

456. Commenters generally agree on 

the need to meet with all affected 

parties, as well as the need to limit some 

meetings for security or confidentiality 

reasons. Certain commenters urge the 

Commission to make clear that 

openness does not extend to a 

requirement to meet with the general 

public and that the meetings are for 

‘‘industry and governmental 

representatives’’ only.255 For example, 

Southern agrees that eligible 

transmission customers and State 

commissions should be allowed to 

participate in the meetings, but states 

that these meetings should not be open 

to the general public to help ensure that 

the focus is on core transmission 

planning and not be diverted to other 

issues. 

457. Transmission providers generally 

note that some meetings will need to be 

limited for CEII concerns or for 

discussion of commercially-sensitive 

information.256 Progress Energy states 

the Commission should be flexible 

regarding the composition of meetings 

and openness, noting that in North 

Carolina meetings involving CEII are 

limited to transmission personnel and 

non-marketing personnel of 

participating LSEs, while other meetings 

in the North Carolina process are open 

to the public. In their reply, NC 

Transmission Planning Participants note 

that they have been able to negotiate 

confidentiality protocols agreeable to 

each of them. Duke believes that 

restrictions on open meetings need to be 

in place when sensitive commercial 

information is being discussed, so that 

personnel engaged in the merchant 

function do not gain access to sensitive 

information about their competitors. 

Indianapolis Power recommends the 

Commission keep existing restrictions 

on access to planning meetings in place 

to preserve current protections on 

security and competitive information. 

TVA states that it is particularly 

concerned with maintaining 

confidentially and asks the Commission 

to defer to NERC and its Regional 

Entities, which TVA says are developing 

procedures for planning. 

458. Commenters also raise issues 

regarding the application of the 

Commission’s Standards of Conduct to 

those that participate in planning 

meetings.257 EEI, for example, believes 

that if information is disclosed during a 

planning meeting and is not 

simultaneously made public, then all 

planning participants—including 

nonjurisdictional entities—should be 

subject to the Commission’s Standards 

of Conduct. APPA understands the need 

to ensure that non-public information 

obtained during planning meetings is 

not utilized to gain an unfair advantage 

in the power market; however, it 

believes that other means short of the 

application of the Standards of Conduct 

would suffice, such as requiring 

simultaneous disclosure of information 

as a ‘‘safe harbor’’ or the use of 

confidentiality agreements.258

459. NRECA and TDU Systems argue 

that meetings should be open and, 

joined by APPA, suggest that 

confidentiality issues can be managed 

with confidentiality agreements and 

other arrangements (such as password 

protected access to information). TAPS 

suggests that access to data be limited to 

transmission dependent utility 

employees not involved in marketing or 

to an outside consultant. California 

Commission stresses that any advisory 

subcommittees must also be open to all 

stakeholders. 

Commission Determination 

460. The Commission adopts the 

NOPR’s proposal and will require that 

transmission planning meetings be open 

to all affected parties including, but not 

limited to, all transmission and 

interconnection customers, State 

commissions and other stakeholders. 

We recognize that it may be appropriate 

in certain circumstances, such as a 

particular meeting of a subregional 

group, to limit participation to a 

relevant subset of these entities. We 

emphasize, however, that the overall 

development of the transmission plan 

and the planning process must remain 

open. We agree with the concerns of 

some commenters that safeguards must 

be put in place to ensure that 

confidentiality and CEII concerns are 

adequately addressed in transmission 

planning activities. Accordingly, we 

will require that transmission providers, 

in consultation with affected parties, 

develop mechanisms, such as 

confidentiality agreements and 

password-protected access to 

information, in order to manage 

confidentiality and CEII concerns. 

Lastly, concerns surrounding the 

application of the Commission’s 

Standards of Conduct to planning 

participants, and whether and how 

these standards should affect access to 

and use of information obtained in the 

planning process, will be discussed 

below. 

c. Transparency 

461. In the NOPR, the Commission 

proposed that transmission providers be 

required to disclose to all customers and 

other stakeholders the basic criteria, 

assumptions, and data that underlie 

their transmission system plans. The 

Commission also sought comment on 

whether the information provided in 

FERC Form 715 (Form 715) is adequate 

and, if not, what additional detail 

should be provided. In addition, the 

Commission sought comment on the 

format for disclosure, including 

protections to address confidentiality 

concerns. 

Comments 

462. Transmission providers generally 

agree that they should provide the basic 

criteria, assumptions, and data for 

planning, but argue that non-public 

utility transmission providers should 

also be required to provide comparable 

information.259 In general, EEI believes 

that information provided during the 

planning process should be treated as 

confidential and not disclosed to the 

general public. 

463. Public power entities and other 

commenters support transparency and 

also are sensitive to confidentiality 

concerns.260 NCPA believes that the 

failure of CAISO to release planning 

data is one of the biggest failings of 

CAISO planning process. Without 

access to criteria, assumptions, and data 

inputs, NCPA argues that customers 

cannot duplicate planning results, nor 

can they independently determine 

whether the assumptions are correct, 

whether the model is producing the 

right results, whether those results are 

being fairly applied in the choice of 

projects to be undertaken, or assess the 

impacts on their own customers. APPA 

suggests that transmission providers be 

required to reduce to writing the 

methodology, criteria, and processes 

they use to develop their transmission 

plans, including how they treat retail 

native loads, in order to ensure that 

standards are consistently applied. 


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261NARUC asks the Commission to re-examine 

the need for its Standards of Conduct rules 

concerning communications between resource and 

transmission planners in light of the mitigation 

provided by the open planning processes proposed 

in the NOPR. 

262E.g., Indianapolis Power, Southern, and Xcel. 

263E.g., Allegheny (with data from PJM) and 

Nevada Companies (with data from WECC). 

264E.g., APPA, California Commission, NCPA, 

CREPC, Seattle, TAPS, and TDU Systems. California 

Commission and CREPC also point out that the load 

forecast information presently used in planning in 

the Western Interconnection is likewise 

insufficient. 

265See also ISO/RTO Council. 

266Much of the information should be available 

to those engaged in transmission planning already 

under reliability Standards TPL–001–0 through 

TPL–004–0 proposed in Docket RM06–16–000. See 

the Reliability Standards NOPR. These standards 

set out detailed requirements for annual studies to 

assess the performance of the transmission system 

and require conducting simulation studies over a 

five-year time horizon, with additional studies as 

needed for the six to ten-year horizon. The 

Commission proposed that planning entities 

conduct ‘‘studies to bracket the range of probable 

outcomes,’’ examining system operation under 

variations in demand levels, existing and planned 

facilities, reactive power resources, generation 

dispatch and transaction patterns, controllable 

CREPC points out that transparency is 

necessary if State regulatory processes 

are to give deference to planning results. 

Sacramento asserts that it may be 

reasonable to allow customers and 

stakeholders access to the planning 

model or at least allow access to a 

comprehensive description of the model 

and methodology, in order to allow 

others to closely replicate the planning 

analysis. Sacramento is joined by 

Imperial in referencing WECC’s ongoing effort to increase planning 

transparency. 

464. NRECA and TDU Systems, 

however, do not believe that a specific 

disclosure principle would be necessary 

if LSEs were truly integrated into the 

planning process. In other words, they 

argue that if the process is truly open, 

then LSEs, as participants in the 

development of the joint plan, should 

already have access to the inputs and 

assumptions underlying the plans and, 

in fact, should have helped develop 

them. 

465. EEI believes that Standards of 

Conduct requirements should be placed 

on all participants in the planning 

process whenever disclosure of 

commercially-sensitive information is 

needed for planning. East Texas 

Cooperatives argues that the Standards 

of Conduct should not be generically 

applied to public power and that such 

issues should be managed with 

confidentiality agreements and case-bycase protective orders. In its reply, 

NRECA also asserts that, while it is 

necessary to protect competitivelysensitive information, there is no basis 

for requiring nonjurisdictional entities 

to comply with the formal separation of 

functions requirements simply because 

they have received information in the 

planning process, as this is inconsistent 

with the cooperative utility business 

model. Rather, NRECA believes 

commercially-sensitive information can 

be handled in other established ways. 

APPA also suggests that Standards of 

Conduct issues can be managed by 

providing for certain ‘‘safe harbors’’ for 

participation, such as simultaneous 

disclosure of information or the use of 

an independent facilitator.261

466. Commenters express a range of 

views on the information found in Form 

715. MidAmerican believes Form 715 to 

be more than adequate and recommends 

shortening or eliminating it. Other 

investor-owned utilities find Form 715 

to be generally sufficient.262 Others 

believe the information in Form 715, as 

currently supplemented by other 

information in the planning process, is 

adequate.263 Duke and WAPA contend 

that Form 715 does not contain 

sufficient information for transmission 

planning, but believe that disclosure of 

further details should be left to 

stakeholders. According to 

NorthWestern, Form 715 contains the 

basic data, but may not always provide 

the needed information. 

467. ISO/RTO Council believes that 

Form 715 data are generally inadequate 

for planning studies, but urges the 

Commission not to attempt to develop 

‘‘standardized forms’’ for these and 

other types of data. CAISO also cautions 

against adopting a standardized form for 

the collection of necessary information, 

because standardized forms do not 

necessarily provide the information 

needed by individual providers. 

468. A number of other commenters 

believe that Form 715 information is 

insufficient.264 APPA and TAPS point 

out that Form 715 does not include all 

the information needed to perform a 

load flow study, including information 

on economic dispatch and interchange, 

and also that Form 715 information is 

out of date when filed. Seattle notes that 

typical sub-regional planning processes 

go into significantly greater detail than 

Form 715 and argues that Form 715 is 

primarily a reliability-focused report 

that seldom delves into economic 

analysis of congestion and transmission 

options that mitigate congestion. 

469. Several commenters contend that 

transparency in the planning process is 

of particular interest to demand 

resources. New Jersey Board suggests 

that each transmission provider’s 

planning process analyze whether 

demand resources or other solutions 

could be considered as an alternative or 

a component of new transmission lines 

or upgrades. New Jersey Board states 

that this analysis should include both 

supply-side and demand-side measures 

such as load management, new building 

codes and energy efficiency standards, 

the use of distributive renewable energy 

systems, and renewable portfolio 

standards. Ohio Power Siting Board 

argues that an open, transparent, and 

inclusive regional planning process 

should include distributed generation, 

demand response, and new technology 

as part of the mix of available options 

for incremental or interim congestion 

relief until longer term solutions can be 

developed and constructed. Fayetteville 

notes its general support for a SEARUC 

joint planning proposal, which includes 

a principle that would require the 

integration of demand response in 

planning. WIRES likewise argues that an 

appropriate grid plan should be based 

on an integrated view of all alternatives, 

including demand response and 

distributed generation. PJM, Midwest 

ISO, and ISO New England emphasize 

that their planning processes already 

provide for the evaluation and 

integration of demand response 

resources.265 Other commenters, such as 

Alcoa and Steel Manufacturer’s 

Association, suggest that demand 

response resources be considered as 

substitutes for certain ancillary services. 

470. In response to its notice 

convening the October 12 Technical 

Conference, the Commission received 

several comments addressing the role of 

demand response in planning. 

Participants in the technical conference 

generally responded that demand 

response programs are considered in 

planning, particularly in the load 

forecasts. Some observed that demand 

response has often been difficult to 

incorporate in long-term plans when it 

is not dispatchable and only available in 

one-year increments. Participants 

stressed that transmission providers 

must have control over a resource 

throughout the planning horizon if they 

are to rely on that resource in lieu of 

constructing upgrades. Some 

participants reported that this capability 

is available from several forms of 

demand response resources. 

Commission Determination 

471. The Commission adopts the 

NOPR’s proposal and will require 

transmission providers to disclose to all 

customers and other stakeholders the 

basic criteria, assumptions, and data 

that underlie their transmission system 

plans.266 In addition, transmission 


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loads and demand-side management, and other 

factors. Id. at P 1047. While we recognize that 

OATT planning is distinct from these proposed 

reliability planning standards, we expect that the 

key data underlying transmission planning will be 

provided in conjunction with reliability standards 

and thus should be available for transmission 

planning when those standards are finalized. 

267See Order No. 888–A at 30,286. 

268We believe this same approach should also 

apply to public utilities that have obtained waivers 

of the Standards of Conduct. 

269The Commission will consider whether 

further changes to the Standards of Conduct would 

facilitate the transmission planning requirement in 

the Standards of Conduct NOPR initiated in Docket 

No. RM07–1–000. See supra note 257. We also 

intend to address the concerns of NARUC with 

regard to waiving the Standards of Conduct 

concerning communications between resource and 

transmission planners in that proceeding. 

270Transmission providers could ensure 

simultaneous disclosure of information through 

such actions as providing all current and potential 

customers and other stakeholders equal access, 

notice, and opportunity to attend planning 

meetings, providing for the contemporaneous 

availability of meeting handouts and minutes on the 

transmission providers’ OASIS or Internet Web 

sites, and requiring that an energy affiliate or 

marketing affiliate employee of the transmission 

provider may not attend a meeting unless a 

representative of at least one additional customer or 

potential customer is present. We believe such 

actions would typically constitute compliance with 

sections 358.5(a) and (b) of the Standards of 

Conduct, 18 CFR 358.5(a)–(b), dealing with 

information access and prohibited disclosure, 

respectively. 

providers will be required to reduce to 

writing and make available the basic 

methodology, criteria, and processes 

they use to develop their transmission 

plans, including how they treat retail 

native loads, in order to ensure that 

standards are consistently applied. This 

information should enable customers, 

other stakeholders, or an independent 

third party to replicate the results of 

planning studies and thereby reduce the 

incidence of after-the-fact disputes 

regarding whether planning has been 

conducted in an unduly discriminatory 

fashion. We note, however, that 

transmission providers cannot be 

expected to fulfill these planning 

obligations unless non-public utility 

transmission providers that participate 

in the planning process make similar 

information available and, for the 

reasons set forth above, we fully expect 

that they will do so. We believe that the 

same safeguards developed as discussed 

above regarding the openness principle, 

such as confidentiality agreements and 

password protected access to 

information, will adequately protect 

against inappropriate disclosure of 

confidential information or CEII. 

472. The Commission also requires 

that transmission providers make 

available information regarding the 

status of upgrades identified in their 

transmission plans in addition to the 

underlying plans and related studies. It 

is important that the Commission, 

stakeholders, neighboring transmission 

providers, and affected State authorities 

have ready access to this information in 

order to facilitate coordination and 

oversight. To the extent any such 

information is confidential or consists of 

CEII, the transmission provider can 

implement the safeguards suggested 

above. 

473. In response to the concerns of 

some commenters regarding the 

disclosure of information to non-public 

utility transmission providers, we 

believe that simultaneous disclosure of 

transmission planning information 

where appropriate alleviates many of 

those concerns. In those instances 

where there is non-simultaneous 

disclosure of information, we find that 

existing reciprocity requirements ensure 

that information is not inappropriately 

shared with the non-public utility 

transmission provider’s marketing 

affiliate. 

474. In Order No. 888–A, the 

Commission clarified that, under the 

reciprocity condition, a non-public 

utility transmission provider must also 

comply with the OASIS and Standards 

of Conduct requirements or obtain 

waiver of them.267 We reiterate that 

non-public utility transmission 

providers should abide by the Standards 

of Conduct with regard to managing 

non-public transmission planning 

information obtained through the 

planning process, consistent with their 

reciprocity obligations. We also note 

that, given the planning process 

required by this Final Rule, it may be 

necessary to revisit the waivers of the 

Standards of Conduct granted to certain 

non-public utility transmission 

providers in the past. We will not do so, 

however, on a generic basis in this 

proceeding. All such existing waivers 

thus shall remain in place. Whether an 

existing waiver of the Standards of 

Conduct should be revoked will be 

considered on a case-by-case basis in 

light of the circumstances surrounding 

the particular transmission provider.268

475. In order for the Final Rule’s 

transmission planning process to be as 

effective as possible, we emphasize that 

all transmission providers, both 

jurisdictional and nonjurisdictional, 

must be assured that the information 

they provide in that process will not be 

used inappropriately in the wholesale 

power market. While we decline to 

require a third party independent 

facilitator as discussed below, we do 

believe that utilizing an independent 

entity may help parties manage 

Standards of Conduct concerns.269

Finally, we wish to emphasize that the 

Commission recognizes that compliance 

with the Standards of Conduct can 

impose costs on small entities, but we 

believe that this concern must be 

balanced against the fact that a 

coordinated and open transmission 

planning process is critical to 

remedying undue discrimination and 

meeting our Nation’s future energy 

needs and that an open planning 

process cannot be fully successful if 

certain entities (whether jurisdictional 

or nonjurisdictional) can use the 

information to obtain an undue 

advantage in power markets. We 

therefore intend to balance the costs of 

confidentiality restrictions with the 

importance of not allowing any entity 

an undue competitive advantage in 

addressing this issue on a case-by-case 

basis. 

476. Although we adopt the foregoing 

protections to ensure that particular 

entities do not gain an inappropriate 

competitive advantage over others, we 

believe that transmission providers 

should make as much transmission 

planning information publicly available 

as possible, consistent with protecting 

the confidentiality of customer 

information. Given that one of the 

primary objectives of the planning 

reforms adopted herein is to allow 

customers to consider future resource 

options, it will be necessary for market 

participants, including the merchant 

function of transmission providers, to 

have access to basic transmission 

planning information in order to 

consider those options. The 

simultaneous disclosure of transmission 

planning information can alleviate the 

Standards of Conduct concerns 

discussed above.270

477. In response to commenter 

concerns regarding the sufficiency of 

planning information currently 

available in the Form 715, we find that 

Form 715, as well as Form 714, have not 

provided customers and others with the 

timely data needed to perform load flow 

studies and other analyses to ensure that 

planning is being conducted on a 

comparable basis. For example, while 

we understand that certain planning 

information is already provided in FERC 

Form No. 714 (Annual Electric Control 

and Planning Area Report) and FERC 

Form 715 (Annual Transmission 

Planning and Evaluation Report), we 

believe that with regard to transparency 

of data and assumptions, Forms 714 and 

715 are limited in a number of ways. An 

important limitation is that information 

is not necessarily available on a 

consistent geographic basis. Form 715 

requires selected powerflow studies by 


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271E.g., Ohio Power Siting Board, New Jersey 

Board, and WIRES. 

272E.g., PJM and ISO–New England. 

273See Staff Report: Assessment of Demand 

Response & Advanced Metering at 97–100 (Docket 

Number AD–06–2–000) (Demand Response Report), 

available at http://www.ferc.gov/legal/staff-reports/ 

demand-response.pdf#xml=http:// 

search.atomz.com/search/ 

pdfhelper.tk?sp_o=1,100000,0. 

274The transmission planning processes we 

require in this Final Rule are not intended in any 

way to infringe upon State authority with regard to 

integrated resource planning. Rather, we believe 

that the transparency provided under an open 

regional transmission planning process can provide 

useful information which will help states to 

coordinate transmission and generation siting 

decisions, allow consideration of regional resource 

adequacy requirements, facilitate consideration of 

demand response and load management programs 

at the State level, and address other factors states 

wish to consider. 

275The Commission noted in the NOPR that for 

network service, some of this information is already 

required by sections 29, 30, and 31 of the pro forma 

OATT, but to the extent it is not, the Commission 

proposed to require customers to provide additional 

information as necessary for the transmission 

provider to develop a system plan. 

276E.g., EEI, Pinnacle, Salt River, and Xcel. 

277TVA states that it is unaware of any 

shortcomings with the existing information 

exchange process and that more specific 

requirements may limit the ability of transmission 

providers to meet changing needs and processes. 

278E.g., APPA, Duke, and Salt River. 

279E.g., NCPA and TDU Systems. 

280See also Bonneville, California Commission, 

Imperial, NCPA, and Seattle. 

control area, while Form 714 requires 

information on control area generation 

and load, including hourly load on a 

planning area. Since these two areas do 

not necessarily coincide, it can be 

difficult to apply the data except for the 

single annual or seasonal system peak. 

Consequently, Form 715 is an 

insufficient basis for broad transmission 

planning purposes and must be 

supplemented by additional 

assumptions and data. 

478. Information may also be difficult 

to compare or apply if a region is larger 

than a single control area. Where the 

peak periods represented in the Form 

715 correspond to different time periods 

in different control areas, separate 

assumptions and information may be 

needed for a study encompassing 

multiple control areas. In addition, each 

control area may include different 

criteria for including facilities in the 

data and additional assumptions will be 

needed to resolve these issues as well. 

Moreover, information on the basis for 

key assumptions is limited. The Form 

715 instructions require a description of 

transmission planning reliability criteria 

and assessment practices, but allow the 

transmitting utility discretion on what is 

reported. As a result, assumptions 

regarding key inputs, such as the load 

forecasts, are not available. Similarly, 

information regarding customer demand 

response is not available. Lastly, Form 

715 requires no information explaining 

the basis for generator dispatch in the 

powerflow cases, nor is any economic 

information provided. For studies of 

system peak reliability, when all 

generators are expected to be running, 

this may not be a significant limitation. 

However, without some basis for 

dispatching the system at other times, it 

becomes difficult or impossible to 

conduct meaningful load flow studies 

for other planning purposes. Therefore, 

we will require the disclosure of 

criteria, assumptions, data, and other 

information that underlie transmission 

plans as described above. 

479. Finally, several commenters 

assert that demand response resources 

should be considered in transmission 

planning.271 Some commenters note 

that certain regions currently are in the 

process of incorporating demand 

response into their transmission 

planning processes.272 Demand 

resources currently provide ancillary 

services in some regions, and this 

capability is in under development in 

some others.273 We therefore find that, 

where demand resources are capable of 

providing the functions assessed in a 

transmission planning process, and can 

be relied upon on a long-term basis, 

they should be permitted to participate 

in that process on a comparable basis.274

This is consistent with EPAct 2005 

section 1223. 

d. Information Exchange 

480. In the NOPR, the Commission 

proposed that network transmission 

customers be required to submit 

information on their projected loads and 

resources on a comparable basis (e.g., 

planning horizon and format) as used by 

transmission providers in planning for 

their native load. The Commission 

further proposed that point-to-point 

customers be required to submit any 

projections they have of a need for 

service over that planning horizon and 

at what receipt and delivery points. The 

Commission sought comment on 

whether specific requirements should 

be adopted for this information 

exchange.275 The Commission also 

stated that transmission providers must 

allow market participants the 

opportunity to review and comment on 

draft transmission plans. 

Comments 

481. Transmission providers suggest 

that they should be responsible for 

developing a schedule and format for 

submission of information and the 

development of a draft plan that 

provides sufficient time for participants 

to review and comment before 

completion of a final plan.276 EEI 

emphasizes the importance of requiring 

comparable information from all 

participants in planning, including nonpublic utilities. EEI maintains that 

similarly-situated participants should 

have comparable information, with 

commercially-sensitive information 

available only to transmission function 

personnel. Duke supports the 

information exchange principle in 

general, but believes the NOPR 

envisions a wider exchange of 

information on loads and resources than 

is appropriate.277 Instead, Duke believes 

that planning participants should agree 

on how much detail will be available. 

WAPA similarly suggests that any 

criteria for information exchange should 

be developed by stakeholders, not the 

Commission. 

482. Although commenters do not 

generally disagree with a requirement 

for point-to-point customers to submit 

projections of their needs for service, 

they question the value of these 

projections if the customers have not 

actually requested service for these 

projected needs.278 Nevada Companies 

state that point-to-point customers 

should provide future use forecasts and 

that the forecast data transferred by all 

entities should be provided for the 

planning horizon in a uniform manner. 

483. Southern is concerned that the 

opportunity for review and comment 

could be construed to apply to draft 

interconnection, system impact, or 

facilities studies under the transmission 

provider’s OATT. Southern argues that 

such a requirement would cause great 

delay and asks the Commission to 

clarify that the transparency 

requirement for review and comment on 

transmission plans is limited to only the 

transmission provider’s draft of its base 

case transmission plan. 

484. Other commenters advance a 

view that joint planning should consist 

of more than providing the transmission 

provider with information and then 

reviewing and commenting on the plans 

it develops; rather, customers need to be 

able to actively participate in the 

development of the planning studies 

and transmission plans.279 APPA 

likewise believes that earlier 

involvement is needed so that projected 

needs are fully understood and 

accounted for in the initial development 

of the plan.280 NCPA stresses that 

reviewing plans is meaningless if there 

is no access to data on how the plan was 

created, how economic evaluation was 


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281E.g., New Jersey Board, Ohio Power Siting 

Board, and WIRES. 

282E.g., California Commission, NCPA, CREPC, 

Salt River, Seattle, and WAPA. 283E.g., Duke and Imperial. 284See also MidAmerican, Progress Energy, and 

Xcel. 

285See also NRECA Reply and Old Dominion. 

286TAPS cites to its ‘‘Balanced Principles for 

Transmission Planning & Expansion,’’ which was 

attached to its NOI comments, for a description of 

the following substantive goals: (1) Reliability/ 

adequacy, (2) accommodating load growth, (3) 

preserving existing transmission rights, (4) access to 

regional competitive generation markets, (5) 

maintaining deliverability, (6) facilitating regional/ 

inter-regional power transfers, and (7) integrating 

new generation into the regional grid. TAPS 

emphasizes that the process should anticipate 

needs and propose solutions before serious 

transmission problems emerge. 

287E.g., ELCON, New Jersey Board, and WIRES. 

performed, and how and why proposed 

upgrades were chosen. Old Dominion 

suggests that planning information and 

data be posted no less than monthly or, 

where appropriate, seasonally. TDU 

Systems and NCEMC stress that LSEs 

should have access to all information at 

the same time since if a transmission 

provider performs studies without 

including other LSEs, it opens the door 

for providers to act on sensitive 

information before releasing it to other 

LSEs. 

485. Some commenters advance the 

view that distributed generation and 

other demand response resources 

should be considered in developing a 

transmission plan.281

Commission Determination 

486. The Commission adopts the 

information exchange principle as to 

both network and point-to-point 

transmission customers. Accordingly, 

we will require transmission providers, 

in consultation with their customers 

and other stakeholders, to develop 

guidelines and a schedule for the 

submittal of information. In order for 

the Final Rule’s planning process to be 

as open and transparent as possible, the 

information collected by transmission 

providers to provide transmission 

service to their native load customers 

must be transparent and, to that end, 

equivalent information must be 

provided by transmission customers to 

ensure effective planning and 

comparability. We clarify that the 

information must be made available at 

regular intervals to be identified in 

advance. Information exchanged should 

be a continual process, the frequency of 

which should be addressed in the 

transmission provider’s compliance 

filing required by the Final Rule. 

However, we expect that the frequency 

and planning horizon will be consistent 

with ERO requirements. 

487. We also believe that it is 

appropriate to require point-to-point 

customers to submit any projections 

they have of a need for service over the 

planning horizon and at what receipt 

and delivery points. We believe that any 

good faith projections of a need for 

service, even though they may not yet 

be subject to a transmission reservation, 

may be useful in transmission planning 

as they may, for example, provide 

planners with likely scenarios for new 

generation development. If the point-topoint customers do not submit such 

projections, then the transmission 

provider cannot later be faulted for 

failing to consider planning scenarios 

that might have taken into account 

reasonable projections of future system 

uses that were not the subject of specific 

service requests. To the extent 

applicable, transmission customers also 

should provide information on existing 

and planned demand resources and 

their impacts on demand and peak 

demand. In addition, stakeholders 

should provide proposed demand 

response resources if they wish to have 

them considered in the development of 

the transmission plan. 

488. Lastly, in response to the 

concerns of some commenters, we 

emphasize that the transmission 

planning required by this Final Rule is 

not intended, as discussed earlier, to be 

limited to the mere exchange of 

information and then review of 

transmission provider plans after the 

fact. The transmission planning 

required by this Final Rule is intended 

to provide transmission customers and 

other stakeholders a meaningful 

opportunity to engage in planning along 

with their transmission providers. At 

the same time, we emphasize that this 

information exchange relates to 

planning, not other studies performed in 

response to interconnection or 

transmission service requests. 

e. Comparability 

489. In the NOPR, the Commission 

proposed that, after considering the data 

and comments supplied by market 

participants, each transmission provider 

develop a transmission system plan that 

(1) Meets the specific service requests of 

its transmission customers and (2) 

otherwise treats similarly-situated 

customers (e.g., network and retail 

native load) comparably in transmission 

system planning. 

Comments 

490. Several commenters support the 

comparability principle,282 and others 

state that existing processes already 

follow this principle.283 EEI urges the 

Commission to emphasize that the 

‘‘comparability’’ principle requires the 

transmission provider or transmission 

owner to treat similarly-situated 

participants comparably in the 

development of a plan, but does not 

require that all participants be treated 

equally. Pinnacle and others support 

comparable treatment of similarlysituated customers and request the 

Commission to confirm that native load 

protections will be recognized in the 

concept of comparability.284 New 

Mexico Attorney General asserts that 

native load and non-affiliated merchants 

and other wholesale customers should 

not be treated comparably, because 

utilities have a statutory obligation to 

serve. 

491. TDU Systems and the NRECA 

repeat the view that comparability 

cannot be achieved if the transmission 

provider is the only one developing the 

plan, which they believe this principle 

contemplates. They argue instead that 

LSEs should be allowed to participate 

actively in the development of the plan 

from the beginning and should have 

equal weight in decision-making. TDU 

Systems believes that comparability 

does not allow for different planning 

standards for certain customers, because 

it may leave rural electric cooperatives 

out of the planning loop.285 TAPS also 

argues that comparability is not enough; 

rather, substantive goals should be 

included.286

492. Noting that not all transmission 

service requests may be granted, 

Southern urges the Commission to 

clarify that the intent of this criteria is 

that the transmission provider plan its 

system so as to be able to reliably serve 

all of its long-term firm commitments on 

its transmission system in accordance 

with its State and Federal legal 

requirements, as well as ERO Standards. 

With regard to RTO and ISO planning, 

NYAPP argues that it is not comparable 

for an RTO or ISO to only plan for bulk 

power facilities, while allowing 

individual transmission owners the 

discretion to plan for lower voltage 

transmission facilities. 

493. Some commenters argue that 

demand resources should be treated 

comparably to other resources in 

transmission planning.287

Commission Determination 

494. The Commission adopts the 

NOPR’s proposal as to the comparability 

principle and will require the 

transmission provider, after considering 

the data and comments supplied by 

customers and other stakeholders, to 

develop a transmission system plan that 

(1) Meets the specific service requests of 


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288As discussed above, we emphasize that the 

obligation imposed herein on transmission 

providers is meant to include transmission owners 

in RTOs and ISOs that no longer have their own 

OATTs, as well as non-public utility transmission 

providers required to comply with the Final Rule’s 

planning process consistent with their reciprocity 

obligations. 

289Additionally, in our discussion of the 

coordination principle above, we clarify that 

transmission planning is the tariff obligation of each 

transmission provider, and as such, ultimate 

responsibility for planning remains with 

transmission providers. Accordingly, we reject the 

arguments made by some commenters that 

comparability requires that customers have equal 

weight in decision-making. 

290E.g., APPA, Bonneville, California 

Commission, Imperial, and NCPA. 

291E.g., East Texas Cooperatives, Salt River, 

Seattle, TVA and WAPA. TVA points out that since 

planning and its principles are just now being 

formed, resources would be better spent on 

developing platforms where interested parties could 

have input into the planning process, as opposed 

to dispute resolution. 

292E.g., Allegheny, Nevada Companies, Pinnacle, 

and Southern. Xcel, however, does not believe any 

dispute resolution process is required in the OATT. 

293See also Duke and MidAmerican. 

294We have already addressed arguments 

concerning our jurisdiction to require a 

transmission planning process. A process for 

resolving disputes that arise from that planning 

process is a necessary incident to it. 

its transmission customers and (2) 

otherwise treats similarly-situated 

customers (e.g., network and retail 

native load) comparably in transmission 

system planning.288 Further, we agree 

with commenters that customer demand 

resources should be considered on a 

comparable basis to the service 

provided by comparable generation 

resources where appropriate. 

495. We are specifically requiring a 

comparability principle to address 

concerns, such as those raised by 

commenters, that transmission 

providers continue to plan their 

transmission systems such that their 

own interests are addressed without 

regard to, or ahead of, the interests of 

their customers. Comparability requires 

that the interests of transmission 

providers and their similarly-situated 

customers be treated on a comparable 

basis. In response to the concerns 

expressed by several commenters, we 

emphasize that similarly-situated 

customers must be treated on a 

comparable basis, not that each and 

every transmission customer should be 

treated the same.289

f. Dispute Resolution 

496. In the NOPR, the Commission 

proposed that transmission providers 

propose a dispute resolution process, 

such as requiring senior executives to 

meet prior to the filing of any complaint 

and using a third party neutral. The 

Commission noted that the 

Commission’s Dispute Resolution 

Service is available to assist 

transmission providers in developing a 

dispute resolution process. The 

Commission also noted that, in addition 

to informal dispute resolution, affected 

parties would have the right to file 

complaints with the Commission under 

FPA section 206. The Commission 

sought comment on whether any 

specific dispute resolution processes 

should be required. 

Comments 

497. Many commenters support the 

proposed dispute resolution 

principle,290 while others believe 

existing processes, including section 12 

of the pro forma OATT, are 

sufficient.291 Other commenters simply 

urge flexibility in the development of a 

dispute resolution process.292 However, 

maintaining that the Commission has no 

legal authority to mandate a regional 

planning process or dispute resolution 

related thereto, Progress states the 

Commission should be flexible and 

allow for a voluntary dispute resolution 

process.293

498. Southern believes that dispute 

resolution should be limited to whether 

a provider has complied with any 

procedural requirements and not be 

utilized by parties to modify a 

transmission plan. APPA, however, 

argues that such an approach would 

relegate customers to an advisory role. 

EEI believes the Commission should 

include principles for dispute resolution 

and should allow stakeholders in the 

regional planning groups to craft their 

own procedures consistent with those 

principles. Reflecting concerns of some 

of its members, EEI cautions against 

mandating dispute resolution that 

includes binding resolution of whether, 

how, where, or when to construct 

additional transmission facilities. 

499. Indianapolis Power believes 

there should be a dispute resolution 

process in place with specific steps 

identified, expressing reservations about 

the vagueness of the current MISO 

process. ATC argues that RTO plans 

should recognize which entity is 

ultimately accountable for building 

transmission, by requiring transmission 

customers that have a dispute with a 

plan first to appeal to the local 

transmission owner to ensure both 

entities fully understand what is being 

requested, before carrying the dispute 

further. 

500. Consistent with its focus on 

integrated joint planning, TDU Systems 

asks that the Commission clarify that a 

dispute resolution process is not being 

required as a principle as an 

acknowledgement that transmission 

providers will retain control over the 

process. As long as LSEs are an integral 

part of the planning process, TDU 

Systems stress that there should be no 

need for an elaborate dispute resolution 

process. 

Commission Determination 

501. The Commission adopts the 

NOPR’s proposal to require 

transmission providers to develop a 

dispute resolution process to manage 

disputes that arise from the Final Rule’s 

planning process.294 An existing dispute 

resolution process may be utilized, but 

those seeking to rely on an existing 

dispute resolution process must 

specifically address how its procedures 

will be used to address planning 

disputes. The dispute resolution process 

should be available to address both 

procedural and substantive planning 

issues, as the purpose for including a 

dispute resolution process is to provide 

a means for parties to resolve all 

disputes related to the Final Rule’s 

planning process before turning to the 

Commission. 

502. We emphasize that the intent of 

the dispute resolution process required 

here is not to address issues over which 

the Commission does not have 

jurisdiction, such as a transmission 

provider’s planning to serve its retail 

native load or State siting issues. As 

discussed above, however, we do intend 

that the planning process required by 

this Final Rule ensure comparability in 

planning between that conducted for a 

transmission provider’s retail native 

load and its similarly-situated 

transmission customers and, therefore, 

issues relating to such comparability 

may be appropriate for the dispute 

resolution process. 

503. Lastly, we encourage 

transmission providers, customers, and 

other stakeholders to utilize the 

Commission’s Dispute Resolution 

Service to help develop a three step 

dispute resolution process, consisting of 

negotiation, mediation, and arbitration. 

Regardless of the process adopted by a 

transmission provider, affected parties 

of course would retain any rights they 

may have under FPA section 206 to file 

complaints with the Commission. 

g. Regional Participation 

504. In addition to preparing a system 

plan for its own control area on an open 

and nondiscriminatory basis, the 

Commission proposed in the NOPR that 

each transmission provider be required 

to coordinate with interconnected 

systems to: (1) Share system plans to 

ensure that they are simultaneously 

feasible and otherwise use consistent 


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295TAPS believes joint planning should include 

at least two transmission providers and be no 

smaller than a State. TAPS suggests that the 

transmission providers’ compliance filings identify 

those other providers it proposes to include in its 

regular regional planning process. 

296NRECA’s comments on regional planning are 

consistent with those of TDU Systems. 

297See also MidAmerican Reply. 

298See Market-Based Rates for Wholesale Sales of 

Electric Energy, Capacity and Ancillary Services by 

Public Utilities, Notice of Proposed Rulemaking, 71 

FR 33102 (Jun. 7, 2006), FERC Stats. & Regs. 

¶ 32,602 (2006). 

299E.g., California Commission, Imperial, and Salt 

River. 

300See also NC Transmission Planning 

Participants Reply and North Carolina Commission 

Reply. Also, in its reply, North Carolina 

Commission urges the Commission not to be overly 

prescriptive with respect to the details of regional 

transmission planning. 

301E.g., Allegheny, Constellation, and Duke. 

assumptions and data, and (2) identify 

system enhancements that could relieve 

‘‘significant and recurring’’ transmission 

congestion (defined below). The 

Commission emphasized that such 

coordination should encompass as 

broad a region as possible, given the 

interconnected nature of the 

transmission grid and the efficiency of 

addressing these issues in a single 

forum. The Commission also recognized 

that, as in the West, it may be 

appropriate to organize regional 

planning efforts on both a sub-regional 

and regional level. The Commission 

sought comment on whether there are 

existing institutions (such as the NERC 

regional councils or sub-regional 

planning groups) that are well-situated 

to perform or coordinate this function. 

Comments 

Regional Scope 

505. EEI agrees that regional planning 

should be encouraged, but urges the 

Commission not to be prescriptive about 

the size of the regions involved. 

According to EEI, the Commission 

should define regional planning as 

planning that involves more than one 

transmission provider and allow the 

regions to define themselves. CAISO 

believes the Commission should leave 

the determination of the sub-regional 

and regional boundaries to transmission 

providers. NC Transmission Planning 

Participants assert on reply that the 

participants in each regional process are 

in the best position determine the 

proper scope of the planning process for 

their region. NRECA argues that 

customers and other stakeholders 

should be allowed to participate in the 

discussion that leads to the delineation 

of regions. NRECA asserts that regions 

should be large enough to minimize the 

potential for seams problems for LSEs in 

multiple control areas. At a minimum, 

NRECA argues that the Commission 

should ensure that all public utility 

transmission providers coordinate with 

their adjoining systems to ensure that 

the needs of LSEs with loads and 

resources in different systems’ areas are 

met. 

506. TDU Systems support mandatory 

regional planning and believe that the 

Commission should specify the criteria 

for determining regions, rather than 

prescribe regional boundaries. In TDU 

Systems’ view, ‘‘regional’’ planning at a 

minimum means something more than 

planning on an individual control area 

basis.295 TDU Systems stress that the 

existence of sub-regional planning must 

not diminish the obligation to plan on 

a broader, more regional level. TDU 

Systems also believe that more than 

coordination is required; rather, 

transmission providers should be 

required to conduct planning on an 

integrated basis with, at a minimum, 

first-tier, adjacent interconnected 

systems. If a transmission provider 

refuses to do so, TDU Systems believe 

that should be considered an exercise of 

vertical market power and the 

transmission provider should lose its 

market-based rate authority. TDU 

Systems also urge the Commission to 

require regional planning for both 

reliability and economic upgrades, in 

order to ensure that competitive market 

development is not retarded by 

inappropriate seams at the borders of 

utility systems.296 In its reply, NRECA 

argues that regional participation must 

be mandatory, because uncoordinated, 

unilateral planning by transmission 

providers severely handicaps LSEs’

assembly of competitive power 

suppliers for their customers. 

507. PJM states that transmission 

providers bordering RTOs should be 

required to participate in the RTO 

planning process, but MidAmerican 

opposes such a requirement and 

believes it already happens in MISO 

anyway. MAPP also opposes such 

mandatory participation, pointing out 

that comparability would then require 

that transmission providers in RTOs 

participate in the planning processes of 

non-RTO providers on their borders as 

well.297 MAPP believes that currentlyexisting regions should have the 

opportunity to adjust their planning 

processes to meet the Commission’s 

guidelines for regional transmission 

planning. 

508. Indianapolis Power emphasizes 

that the regional scope of a transmission 

provider’s planning process should 

consider grid topology and historical 

usage to avoid regions that are too broad 

or unwieldy. Indianapolis Power 

believes that the current MISO region 

may be an example of a region that is 

too large, but nevertheless asserts that 

MISO should have the primary role in 

coordination, with regional councils in 

supporting roles. AWEA recommends 

nine planning regions that coincide 

with the nine regions being established 

for Regional Triennial Reviews in the 

market-based rate rulemaking in Docket 

No. RM04–7–000: 298 PJM, New York, 

New England, Midwest, SPP, Southeast, 

California, Northwest, and Southwest. 

509. LDWP and Salt River suggest that 

continued participation in existing 

regional and sub-regional groups should 

satisfy the expectation that municipallyowned transmission providers 

participate in open and transparent 

regional planning processes. Other 

commenters express a similar concern 

that the Commission not mandate any 

procedures that would interfere with the 

processes the West has already 

established.299 New Mexico Attorney 

General believes that those already 

engaged in a planning process should be 

allowed a waiver. 

510. NARUC urges the Commission to 

clarify that planning proposals should 

not interfere with or undermine existing 

regional planning efforts, such as those 

conducted by RTOs and in non-RTO 

areas.300 Project for Sustainable FERC 

Energy Policy recommends that the 

Commission use the Bonneville and 

PJM planning processes as models for 

evaluating transmission provider 

compliance. Arkansas Commission 

believes that the active involvement of 

states can be a catalyst for regional 

planning. 

511. National Grid believes the 

principles of coordination, openness, 

and transparency should extend to 

inter-regional planning and requests 

clarification that this is the 

Commission’s intent for neighboring 

regions in a single interconnect. 

Existing Institutions 

512. Regarding the Commission’s 

request for comment on whether there 

are existing institutions that are wellsituated to coordinate regional 

participation, commenters express 

differing views regarding the identity of 

the regional coordinator and the size of 

the region over which entities should be 

required to coordinate. Some 

transmission provider commenters cite 

NERC regions and regional councils as 

well-suited for coordinating regional 

participation.301 Taking an opposite 

view, ISO/RTO Council maintains that 

RTOs and ISOs are the best models for 


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302 In general, WECC and its sub-regional groups 

have adopted an overall division of labor whereby 

WECC has undertaken facilitation of interstate, 

commercial transmission projects and the subregional groups have facilitated the planning of 

their member providers. 

303E.g., ColumbiaGrid, MidAmerican, Nevada 

Companies, NorthWestern, Pinnacle, and Xcel. 

304E.g., Anaheim, APPA, California Commission, 

Imperial, LDWP, NCPA, PGP, Public Power 

Council, CREPC, Salt River, Santa Clara, Seattle, 

TANC, WAPA, and Western Governors. APPA 

notes, however, that not all of its members that 

support the WECC planning process support those 

within California. 

305Public Power Council does not support 

expansion of WECC’s role in coordinating planning 

beyond its current activities, as it believes WECC’s 

strength lies in the area of reliability and not 

planning and, therefore, that WECC would be best 

served by focusing on reliability and standards 

enforcement, rather than as a participant (as a 

facilitator or otherwise) in commercial matters. 

306WAPA points out that certain broad functions 

related to planning can be coordinated at the 

regional level, but that sub-regional planning is 

necessary in an expansive regional area, such as 

WAPA’s service territory, in order to provide focus 

and detail. 

307E.g., LDWP, New Mexico Attorney General, 

and Salt River. LDWP also cites its involvement in 

the Public Power Initiative of the West, CAISO, and 

the Western Arizona Transmission System group. 

308Anaheim believes that the CAISO process does 

not currently proactively evaluate the adequacy of 

the system or itself propose projects that will 

enhance reliability or efficiency and is based 

entirely upon plans presented to it by transmission 

owners. It notes, however, that CAISO has proposed 

reforms to address these issues. See also Anaheim 

Reply. 

309E.g., Bonneville, ColumbiaGrid, PGP, Public 

Power Council, and Seattle. APPA also notes its 

members’ support for the sub-regional processes in 

the Northwest. 

regional participation, because regional 

reliability organizations do not have 

mandates or authority to ensure that 

adequate system expansion occurs on a 

coordinated basis. 

513. MISO is concerned the 

Commission intends to shift 

transmission planning responsibility 

from RTOs to the Regional Entities 

under the ERO, arguing that these 

entities have neither a sufficient level of 

independence nor a track record in 

transmission planning. TDU Systems 

suggest that RTOs, where they exist, 

should perform the regional planning 

function, although in some other 

instances it may be the regional 

reliability organizations. Although 

CAISO states that a larger regional entity 

with the authority to order expansion 

has some appeal, it contends there are 

too many hurdles to creating such an 

entity in the West. TAPS suggests a 

‘‘Regional Joint Planning Committee’’

that is not dominated by transmission 

providers, which would direct the study 

process and be responsible for the 

development of uniform planning 

criteria, assumptions for base and 

changed cases, and transmission plans. 

Existing Regional Planning Processes 

The West 

514. Transmission provider 

commenters in the West (outside 

California) generally recommend the 

Western Electricity Coordinating 

Council (WECC) 302 as a successful 

institution and an appropriate model for 

designating regions and developing a 

plan for the interconnection.303 Many 

public power entities and others in the 

West also support WECC and suggest 

that it should be a primary focus when 

deciding which institution can provide 

independent regional review and 

coordination of grid planning in the 

West.304 For example, California 

Commission notes that WECC’s 

Transmission Expansion Planning 

Policy Committee allows for the 

consolidated needs of all the system 

operators in the Western 

Interconnection to be considered in the 

planning process and considers both 

reliability and economic transmission 

planning. California Commission also 

stresses that the processes in the West 

have resulted in transmission being 

built. Utah Municipals, however, are 

critical of the WECC process, and in 

reply, assert that the WECC process does 

not allow for effective stakeholder 

input, but merely review of 

transmission plans once they are 

formed. Utah Municipals also believe 

that sub-regional groups in its area (e.g., 

the Southwest Transmission Expansion 

Plan (STEP)) are more effective and 

urges the Commission to focus on the 

effective implementation of joint 

plans.305

515. Other commenters support the 

sub-regional planning processes in the 

West as well, and generally believe the 

Commission should look to each subregion’s existing processes and 

institutions.306 For example, 

commenters in the Southwest and 

California also support the sub-regional 

groups located in that region (e.g., STEP 

and the Southwest Area Transmission 

Expansion Planning group (SWAT)).307

California Commission also supports the 

CAISO planning process and states that 

CAISO works closely with stakeholders 

to proactively identify needed, cost 

effective transmission solutions through 

an open, non-discriminatory process 

that has resulted in $1.8 billion in 

transmission being constructed.308 In its 

reply, NCPA emphasizes that the 

Commission should not equate the 

CAISO planning process with a 

California-wide process, because not all 

transmission providers in California are 

members of CAISO. However, California 

Commission notes that California, with 

the support of WECC, has begun the 

work of creating a California-wide subregional planning group that includes 

the large, unregulated municipal 

utilities that do not participate in 

CAISO. 

Northeast 

516. PJM, NYISO, and ISO New 

England all have transmission planning 

processes that have been approved by 

the Commission. ISO/RTO Council cites 

billions of dollars of transmission 

investment in the Northeast as an 

example of the success of these 

transmission planning processes and 

argues that these processes all satisfy 

the Commission’s principles for 

coordinated, open, and transparent 

planning. PJM maintains that its 

Regional Transmission Expansion 

Planning Protocol is a successful and 

comprehensive regional planning 

paradigm. ISO New England also argues 

that its transmission planning meets the 

principles and further points to the 

Northeastern ISO/RTO Planning 

Coordination Protocol as providing 

coordinated planning across the entire 

Northeast region. 

517. Utilities in the Northeast are 

generally supportive of the transmission 

planning in the Northeast RTOs. 

Designated NY Transmission Owners 

contend that the NYISO Comprehensive 

Reliability Planning Process is fully 

open, coordinated, and transparent and 

meets or exceeds each of the eight 

principles in the NOPR. PSEG believes 

the PJM planning process embodies the 

NOPR principles. Constellation cites the 

planning processes in PJM and the 

NYISO as examples of planning 

processes that, while not perfect, should 

serve as models for compliance filings 

by others. Old Dominion, however, 

expresses concern over continuing 

domination of transmission planning by 

transmission owners, but nevertheless 

commends PJM for recent efforts to 

include more stakeholder input in the 

planning process. National Grid is 

generally supportive of ISO New 

England’s planning process. 

Northwest 

518. Several commenters in the 

Northwest generally support the 

Northwest Power Pool and the 

ColumbiaGrid process (which will 

provide for a biennial transmission 

expansion plan for certain entities in the 

Northwest).309 Also, two groups in the 

Northwest are forming to address subregional planning in that region—the 

ColumbiaGrid group and the Northern 

Tier Transmission Group—but it is not 


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310See also TDU Systems Reply. 

311We note that FMPA filed joint comments on 

behalf of itself and the Midwest Municipal 

Transmission Group. 

312See also Seminole Reply. 

313As provided for above, transmission providers 

will be required to file a ‘‘strawman’’ proposal for 

compliance with the Final Rule’s planning process 

within 75 days after publication of the Final Rule 

in the Federal Register that includes, among other 

things, a specification of the broader region in 

which they propose to conduct coordinated 

regional planning. The Commission will then 

convene technical conferences in several broad 

regions around the country to assist the participants 

in developing the appropriate regional planning 

groups to the extent they do not already exist. 

yet clear how such groups intend to 

coordinate with each other. 

Southeast 

519. The public power commenters in 

the Southeast were not as supportive of 

the existing regional and sub-regional 

planning processes in their region. TVA 

and Santee Cooper generally support the 

process conducted by the Southeast 

Electric Reliability Council (SERC), and 

Santee Cooper notes that it has had a 

formal joint planning process with its 

largest wholesale customer for more 

than 25 years. APPA, however, notes 

that its members did not generally 

endorse existing regional entities in the 

Southeast. APPA states that SERC, for 

example, just ‘‘rolls up’’ the 

transmission plans of the transmission 

providers, and some working groups 

currently exclude non-transmission 

owners.310

North Carolina 

520. NCEMC points to the North 

Carolina Transmission Planning 

Collaborative (NC Transmission 

Planning), a joint planning process with 

an independent facilitator, in North 

Carolina. NCEMC emphasizes that more 

than regional coordination is required 

and that regional planning needs to be 

more than mere stakeholder review and 

must allow for full participation of LSEs 

in planning. NCEMC stresses that 

effective regional planning requires 

participation on a sufficient scale to 

encompass all LSEs within a natural 

market area in order to properly address 

seams issues and impacts on 

neighboring systems. Fayetteville does 

not believe NC Transmission Planning 

complies with the planning principles 

outlined in the NOPR. 

Midwest 

521. MISO believes its current 

transmission planning process 

represents industry best practices, 

arguing that it is open and inclusive and 

provides multiple opportunities for 

entities to participate. MISO 

Transmission Owners endorse the 

existing MISO transmission planning 

process and believe that the process 

already provides for regional planning 

and an open process with stakeholder 

involvement. Ohio Power Siting Board, 

however, claims that MISO’s 

transmission planning process should 

not be regarded as best practices, stating 

that it is not sufficiently open and 

transparent. It also suggests that RTOs 

merely ‘‘rubber stamp’’ investor-owned 

utility plans. Additionally, FMPA 311

notes that MidAmerican has recently 

made efforts to engage in more proactive 

planning and has offered joint 

transmission investment opportunities. 

FMPA also points to its membership in 

CAPX 2020, a consortium of Upper 

Midwest utilities, which are jointly 

studying and planning for the needs of 

regional transmission. However, FMPA 

makes clear that it believes smaller 

customers nevertheless need a tariff 

requirement for planning to ensure that 

their needs are addressed. 

Florida 

522. While the Florida Commission 

believes that the planning process 

conducted by the Florida Reliability 

Coordinating Council (FRCC) is 

adequate, others, such as FMPA, do 

not.312 Florida Commission states that 

the FRCC has instituted a transparent 

and inclusive planning process whereby 

utilities, generators, and marketers 

participate in joint transmission 

planning studies and evaluate 

impediments to transfer capability and 

determine solutions to congestion in 

order to enhance the reliability of the 

FRCC system. 

Commission Determination 

523. We adopt the NOPR’s proposal to 

include a regional participation 

principle as a component of the Final 

Rule’s transmission planning process. 

Accordingly, in addition to preparing a 

system plan for its own control area on 

an open and nondiscriminatory basis, 

each transmission provider will be 

required to coordinate with 

interconnected systems to (1) Share 

system plans to ensure that they are 

simultaneously feasible and otherwise 

use consistent assumptions and data 

and (2) identify system enhancements 

that could relieve congestion or 

integrate new resources (discussed 

further below).313

524. As discussed earlier in this Final 

Rule, since the advent of open access, 

power markets have become regional in 

almost every area of the country. These 

regional markets provide opportunities 

for wholesale customers to access 

competitive sources of supply, rather 

than relying exclusively on local 

generation, including resources owned 

by their local transmission provider. 

However, as discussed above, it is not 

in the economic self-interest of 

transmission providers to expand the 

grid to permit access to competing 

sources of supply. A transmission 

provider has little incentive to upgrade 

its transmission capacity with its 

interconnected neighbors if doing so 

would allow competing suppliers to 

serve the customers of the transmission 

provider. We therefore find, as 

discussed in greater detail above, that 

greater coordination and openness in 

transmission planning is required, on 

both a local and regional level, to 

remedy undue discrimination. The 

coordination of planning on a regional 

basis will also increase efficiency 

through the coordination of 

transmission upgrades that have regionwide benefits, as opposed to pursuing 

transmission expansion on a piecemeal 

basis. The specific features of the 

regional planning effort should take 

account of and accommodate, where 

appropriate, existing institutions, as 

well as physical characteristics of the 

region and historical practices. 

525. The Commission is encouraged 

that a number of voluntary coordinated 

and regional planning efforts have been 

developed throughout the country, 

including those administered by RTOs 

and ISOs and in certain sub-regions of 

the West and Southeast. For example, 

each of the Commission-approved RTOs 

in the Northeast, Midwest, and 

Southwest, as well as CAISO, provide 

for a coordinated and regional planning 

process with stakeholder input from 

each industry segment. There are 

several other promising efforts to 

establish voluntary coordinated and 

regional planning efforts around the 

country as noted in our discussion 

above of existing regional planning 

processes. 

526. The Commission fully supports 

these existing efforts and believes some 

of them are consistent in significant 

respects with the nature of the reforms 

adopted in this Final Rule. In those 

regions and sub-regions that already 

have adopted significant reforms, the 

Commission’s planning reforms may 

require only modest changes, while 

other regions and sub-regions may need 

to undertake more significant changes to 

the way in which transmission currently 

is planned. The Commission will not in 

this Final Rule opine on the 

characteristics of existing regional 

planning processes or their consistency 

with the reforms we adopt today. 


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314E.g., APPA, Arkansas Commission, California 

Commission, East Texas Cooperatives, Entegra, 

NCPA, CREPC, Southwestern Coop, TDU Systems, 

and WIRES. 

315E.g., American Transmission, EEI, Progress 

Energy, and Southern. 

316Entegra, however, replied to Southern’s 

assertion that congestion studies can be misleading, 

stating that congestion studies did not need to be 

misleading, and were, on the contrary, necessary for 

customers to assess the costs of managing versus 

eliminating congestion. 

317E.g., Imperial, MidAmerican, Nevada 

Companies, NorthWestern, Pinnacle, Salt River, 

SWAT, WestConnect, and Xcel. 318Others assert that the DOE studies will be 

useful but not necessarily duplicative of the 

congestion study principle. E.g., APPA and Salt 

River. 319Bonneville agrees that the costs of congestion 

itself are not readily available to transmission 

providers and that customers are better positioned 

to determine this. 

Rather, each process will be addressed 

in the context of the relevant 

compliance filing. In general, however, 

the Commission urges participants in 

existing regional planning processes to 

closely examine whether improvements 

may be implemented to ensure that each 

regional planning process is fully 

consistent with the requirements of this 

Final Rule. 

527. Finally, the Commission 

acknowledges the importance of 

identifying the appropriate size and 

scope of the regions over which regional 

planning will be performed. We agree 

that transmission providers, customers, 

affected State authorities, and other 

stakeholders should be involved in 

developing those regions. We decline to 

mandate the geographic scope of 

particular planning regions at this time. 

The scope of a particular planning 

region should be governed by the 

integrated nature of the regional power 

grid and the particular reliability and 

resource issues affecting individual 

regions and sub-regions. In very large 

regions, there may well be both subregional and regional processes. For 

example, in the West there are various 

sub-regional processes in addition to a 

WECC regional planning process. We 

believe that such an approach can work, 

provided that there is adequate scope to 

the sub-regional processes and adequate 

coordination between sub-regions. We 

expect sub-regions to coordinate as 

necessary to share data, information and 

assumptions as necessary to maintain 

reliability and allow customers to 

consider resource options that span the 

sub-regions. 

528. In response to the commenters 

that indicate that regional planning 

already occurs today as part of the 

NERC planning process, we support any 

such processes, but reiterate that, if they 

are to meet the requirements of the Final 

Rule, they must be open and inclusive 

and address both reliability and 

economic considerations. As we discuss 

elsewhere in this section, customers 

must be allowed to request that 

economic upgrades be studied and, 

therefore, we will require transmission 

providers to coordinate on these issues 

as necessary in sub-regional or regional 

planning processes. To the extent the 

NERC processes are not considered 

appropriate for such economic issues, 

individual regions or sub-regions may 

develop alternative processes. 

h. Economic Planning Studies 

529. In the NOPR, the Commission 

proposed to require transmission 

providers to prepare studies identifying 

‘‘significant and recurring’’ congestion 

and post such studies on their OASIS. 

The Commission explained that the 

studies should analyze and report on (1) 

The location and magnitude of the 

congestion, (2) possible remedies for the 

elimination of the congestion, in whole 

or in part, (3) the associated costs of 

congestion, and (4) the cost associated 

with relieving congestion through 

system enhancements (or other means). 

The Commission sought comment on 

how to define ‘‘significant and 

recurring’’ congestion, such as by 

reference to generation redispatch, 

repeated denials of service requests, 

zero ATC, frequent curtailments or a 

combination of these factors. The 

Commission noted that the required 

congestion studies would address both 

‘‘local’’ congestion (i.e., within the 

transmission provider’s system) and 

congestion between control areas and 

sub-regions. The Commission stated that 

the purpose of this requirement is to 

ensure that affected market participants, 

State commissions, and the Commission 

understand both the costs of recurring 

transmission congestion and the 

alternatives for relieving it. The 

Commission sought comment on how 

this information should be used by 

transmission providers and market 

participants to address significant and 

recurring congestion. 

Comments 

Need for Congestion Studies 

530. The Commission’s proposal 

regarding congestion studies gave rise to 

a wide range of comments. Some 

commenters generally support requiring 

congestion studies.314 East Texas 

Cooperatives asserts that congestion 

studies will greatly assist in the 

development of transmission plans, 

enable planning participants to focus on 

key elements of the system and assist in 

the preparation of the congestion 

studies conducted by DOE. NRECA also 

supports requiring congestion studies, 

but urges the Commission not to be 

prescriptive. 

531. Other commenters recommend 

eliminating the requirement.315

Southern, for example, argues that 

congestion studies could be misleading 

because they can imply that all 

congestion needs to be remedied.316

Duke, South Carolina E&G, and 

Southern agree that separate studies of 

congestion, beyond studies performed to 

meet service requests, should not be 

required. Rather than mandating 

congestion studies, Southern argues that 

the Commission should allow 

participants to determine which types of 

transmission studies have merit. Other 

commenters believe that, if congestion 

studies are required, they should be 

performed at a regional level rather than 

by each transmission provider 

individually.317

532. The EEI position is 

representative of entities calling for 

elimination of the congestion study 

principle. EEI asserts that these studies 

in large part would be duplicative of the 

studies being performed by DOE 

pursuant to EPAct 2005.318 EEI also 

argues that these studies would be 

costly and time-consuming and that 

transmission providers generally do not 

have access to information needed for 

cost impact analysis and consequently 

cannot assess the cost of constraints.319

TDU Systems assert on reply that it is 

difficult to imagine that providers do 

not have the information needed or 

means to determine the location and 

magnitude of congestion on their 

systems, since they perform this 

function for themselves already. TDU 

Systems add that customers will readily 

provide any information needed for 

congestion studies, as it is in their 

interest to do so. APPA believes that 

customers should be expressly required 

to produce information to help 

determine the cost of congestion (e.g., 

the additional cost to them of running 

or purchasing more expensive 

generation). TDU Systems also argues 

that the distinction between economic 

and reliability upgrades is a fiction and 

should be disregarded. 

533. In the Western Interconnection, 

entities maintain that WECC will be 

performing congestion studies that 

should meet the requirement. As a 

result, they assert that this principle 

should not be applied to individual 

transmission providers in the West, but 

that these providers should be permitted 

to meet the principle through the 

interconnection-wide congestion studies 

conducted by WECC. Tacoma notes that 

ColumbiaGrid is considering the 


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320E.g., Allegheny, FirstEnergy, Indianapolis 

Power, and PSEG. 321See also Indicated Parties Reply. 

services it can offer in congestion 

assessment at the sub-regional level in 

the Northwest. Other commenters, such 

as California Commission, Salt River, 

and Seattle, support a congestion 

studies requirement but believe it 

should not be required annually but 

rather biennially or triennially. 

534. In the Eastern Interconnection, 

RTOs and ISOs, and entities in RTOs 

and ISOs, believe congestion studies are 

not needed where LMP markets are in 

place or are satisfied by RTO or ISO 

studies.320 Entergy argues that the 

congestion studies that will be 

performed by its independent 

coordinator of transmission should meet 

this requirement. 

Determining ‘‘Significant and 

Recurring’’ Congestion 

535. A variety of commenters provide 

suggestions as to what constitutes 

‘‘significant and recurring’’ congestion. 

TDU Systems believe that there should 

be a presumption of congestion if a 

transmission provider posts zero ATC. 

TDU Systems, APPA, and Bonneville 

believe that other indications of 

significant and recurring congestion 

include the need for frequent generation 

redispatch, frequent curtailments for 

reasons other than force majeure, and 

repeated denials of requests for firm 

transmission service. California 

Commission and CREPC suggest a 

similar approach based on a comparison 

of ATC and schedules with historical 

flows and an assessment of denied 

requests, but emphasize that the process 

should be forward-looking as well. 

536. APPA suggests the use of metrics 

to measure congestion (e.g., reporting on 

all congestion costs that exceed five 

percent of base energy costs and five 

percent of the hours in a season). 

California Commission also suggests the 

use of metrics, but cautions that there 

may be East-West differences. 

Sacramento stresses that such metrics 

should depend on whether the system 

being studied uses LMP or physical 

rights. In its view, financial metrics are 

most useful in LMP markets, while 

congestion in physical markets should 

be determined by paths that have been 

derated by a material percent of their 

nominal rating over a certain number of 

hours in a season. 

537. Santa Clara suggests that 

significant and recurring congestion 

exists when congestion costs over a 

given path during the high use season 

approach or exceed the depreciation 

plus other fixed costs on the new 

facilities that would eliminate 

congestion on the path. Additionally, 

Santa Clara emphasizes that if, 

redispatch is necessary on an ongoing 

basis, this should be taken as an 

indication that new facilities need to be 

built. 

538. New York Commission urges the 

Commission to utilize NYISO’s process 

for measuring historical congestion—

defined as the short-run production (i.e., 

dispatch) costs that could be avoided by 

system enhancements, as this represents 

the savings to society compared to the 

cost to society of investing in the system 

enhancement. New York Commission 

also cautions the Commission against 

using analyses focused on the impacts 

of transmission investments on 

wholesale energy prices, because these 

energy price impacts may be temporary 

and offset by changes in generation 

investments. TDU Systems and Old 

Dominion stress that in PJM significant 

and recurring congestion should be 

based on total gross congestion and not 

the much smaller and unrealistic 

measure of unhedgeable congestion, as 

this masks the economic reality that 

congestion itself has an economic 

cost.321

539. The Organizations of MISO and 

PJM States do not believe the Final Rule 

should address criteria for determining 

significant and recurring congestion, but 

should require each transmission 

provider to file criteria for inclusion and 

cost responsibility for upgrades that are 

included in the transmission plan to 

remedy congestion. 

540. Seattle asserts that current 

OASIS standards do not support 

consistent tracking of service denials 

and that this inhibits the evaluation of 

congestion. Seattle also points out that 

the costs of congestion may be difficult 

to quantify because reliability dispatch 

is a reactive tool used only after service 

requests have been denied and 

prescheduled limits imposed and, 

therefore, foregone transactions will not 

be known to the transmission provider. 

541. Ohio Power Siting Board asserts 

that distributed generation, demand 

response, and new technologies should 

be available to relieve congestion until 

longer-term solutions can be 

implemented. 

Commission Determination 

542. The Commission adopts the 

NOPR proposal and retains a congestion 

study principle as part of the Final 

Rule’s transmission planning process; 

however, we modify and clarify the 

principle in certain important respects 

in response to the comments received. 

At the outset, we wish to clarify that our 

primary objective in adopting this 

principle is to ensure that the 

transmission planning process 

encompasses more than reliability 

considerations. Although planning to 

maintain reliability is a critical priority, 

it is not the only one. Planning involves 

both reliability and economic 

considerations. When planning to serve 

native load customers, a prudent 

vertically integrated transmission 

provider will plan not only to maintain 

reliability, but also consider whether 

transmission upgrades or other 

investments can reduce the overall costs 

of serving native load. Such upgrades 

can, for example, reduce congestion 

(redispatch) costs or integrate efficient 

new resources (including demand 

resources) and new or growing loads. 

Thus, to represent good utility practice 

and provide comparable service, the 

transmission planning process under 

the pro forma OATT must consider both 

reliability and economic considerations. 

The purpose of this principle is to 

ensure that the latter is considered 

adequately in the transmission planning 

process. 

543. Some commenters argue that 

economic upgrades should be 

considered only in the context of 

individual requests for service under the 

pro forma OATT. The Commission 

disagrees. The process for addressing 

individual requests for service under the 

pro forma OATT is adequate for 

customers who request specific 

transmission rights to purchase power 

from a particular resource in a particular 

location during a defined time period. 

However, it does not provide an 

opportunity for customers to consider 

whether potential upgrades or other 

investments could reduce congestion 

costs or otherwise integrate new 

resources on an aggregated or regional 

basis outside of a specific request for 

interconnection or transmission service. 

It thus limits, for example, groups of 

customers from considering more 

comprehensive solutions to 

transmission congestion, including 

investment in demand response. It also 

limits multiple LSEs from considering, 

on a more aggregated basis, whether 

particular upgrades may represent the 

most economic means of integrating 

new generation resources (e.g., wind 

resources) located in a common area 

that could be accessed by many 

customers. The Commission believes 

such coordinated studies can, for system 

planning purposes, be more beneficial 

than studies performed on a request-byrequest basis. We also find that they are 

consistent with the requirement to 

provide comparable service. 


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322See PJM Interconnection, L.L.C., 117 FERC 

¶ 61,218 (2006), reh’g pending. 

323The example of five to ten studies mentioned 

in this Final Rule is merely illustrative. We 

recognize that the facts of each case will be used 

to determine the number of high priority studies 

allowed under a transmission plan. 

324This cost recovery mechanism is comparable 

and nondiscriminatory because the transmission 

provider already has the ability to include in its pro 

forma OATT rates the cost of service associated 

with studies performed on behalf of native load 

customers. 

Transmission providers are not limited, 

in serving native load customers, to 

studying potential transmission 

upgrades only in the context of specific 

requests for service under the pro forma 

OATT. 

544. Some transmission providers 

appear to object to this principle 

because they fear that an obligation to 

study potential upgrades is equivalent 

to an obligation to fund or build such 

upgrades. We clarify that this is not the 

intent of this principle. There is a 

difference between a planning process 

that is coordinated and open and one 

that dictates construction and cost 

responsibility. Both considerations are 

important, but, as we explain above, 

they are distinct. The purpose of this 

principle is to ensure that customers 

may request studies that evaluate 

potential upgrades or other investments 

that could reduce congestion or 

integrate new resources and loads on an 

aggregated or regional basis (e.g., wind 

developers), not to assign cost 

responsibility for those investments or 

otherwise determine whether they 

should be implemented. The issue of 

cost allocation is addressed in Principle 

No. 9 below. 

545. The Commission also disagrees 

with the contentions of certain RTOs or 

ISOs that they need not comply with 

this principle. Although RTO and ISO 

planning processes tend to be more 

open and coordinated than the 

processes used by vertically-integrated 

transmission providers, this does not 

mean that RTO or ISO processes 

adequately address, in all 

circumstances, investments that are 

primarily economic in nature. When 

many RTO and ISO planning processes 

were created, they focused primarily on 

system enhancements necessary to 

maintain reliability. However, in recent 

years, as congestion has increased and 

generation reserve margins have 

declined, many RTOs and ISOs have 

taken increasingly progressive steps to 

identify investments that could reduce 

congestion and/or integrate new 

resources. For example, we recently 

approved a proposal by PJM to 

significantly enhance its RTEP planning 

process.322 We applaud these efforts as 

consistent with the direction of the 

reforms adopted herein. However, we 

decline to provide a blanket exception 

for RTOs and ISOs. Each RTO or ISO 

must show that its planning process is 

consistent with or superior to the 

requirements of the Final Rule in all 

respects. 

546. Some commenters express 

concern that this principle may result in 

costly congestion studies that are of 

little interest or value to customers. Our 

intent is not to impose a costly study 

requirement that is unrelated to the realworld concerns of consumers. In the 

NOPR, we sought comment on whether 

specific metrics (e.g., zero ATC or TLR 

frequency) should be used to trigger the 

congestion study requirement. After 

considering the comments on this topic, 

we do not believe that any single metric, 

or group of metrics, is adequate for that 

purpose. Relying on discrete metrics in 

this instance would risk both over- and 

under-inclusiveness—i.e., triggering too 

many studies, thereby imposing cost 

burdens on transmission providers that 

are not appropriate, or triggering too few 

studies, thereby omitting important 

studies that could help customers 

identify cost-effective solutions to 

congestion. Additionally, we direct 

transmission providers, in consultation 

with their stakeholders during 

development of their Attachment K 

compliance filings (as discussed above), 

to develop a means to allow the 

transmission provider and stakeholders 

to cluster or batch requests for economic 

planning studies so that the 

transmission provider may perform the 

studies in the most efficient manner. We 

will also require the requests for 

economic planning studies, as well as 

the responses to the requests, be posted 

on the transmission provider’s OASIS or 

Web site, subject to confidentiality 

requirements. 

547. The Commission will modify the 

principle to allow customers to choose 

the studies that are of the greatest value 

to them. Specifically, we are modifying 

the principle to require that 

stakeholders be given the right to 

request a defined number of high 

priority studies annually (e.g., five to 

ten studies) 323 to address congestion 

and/or the integration of new resources 

or loads. The intent of this approach is 

to allow customers, not the transmission 

provider, to identify those portions of 

the transmission system where they 

have encountered transmission 

problems due to congestion or whether 

they believe upgrades and other 

investments may be necessary to reduce 

congestion and to integrate new 

resources. The customers should be able 

to request that the transmission provider 

study enhancements that could reduce 

such congestion or integrate new 

resources on an aggregated or regional 

basis without having to submit a 

specific request for service. This 

approach ensures that the economic 

studies required under this principle are 

focused on customer needs and 

concerns, not administratively 

determined metrics that may bear no 

necessary relation to those concerns. 

Once such studies are requested, the 

transmission provider would conduct 

the studies, including appropriate 

sensitivity analyses, in a manner that is 

open and coordinated with the affected 

stakeholders. The cost of the defined 

number of high priority studies would 

be recovered as part of the overall pro 

forma OATT cost of service.324 By 

limiting this principle to a defined 

number of high priority studies 

annually, we are not precluding 

stakeholders from requesting additional 

studies. However, to provide 

appropriate financial incentives, the 

stakeholder(s) requesting these 

additional studies would be responsible 

for paying the cost of such studies. 

548. We also will modify this 

principle with respect to the scope of 

the studies being performed. The 

Commission proposed in the NOPR that 

the studies address ‘‘significant and 

recurring congestion.’’ However, the 

Commission also sought comment on 

whether, in addition, the study process 

should address upgrades associated 

with new generation resources and 

provide information needed to 

proactively evaluate such resources. We 

discuss the comments on this proposal 

in more detail below, but, as described 

therein, we agree that the study process 

should incorporate such considerations. 

We therefore modify Principle No. 8 to 

encompass the study of upgrades to 

integrate new generation resources or 

loads on an aggregated or regional basis. 

This is appropriate because congestion 

can limit both the efficient dispatch of 

existing generation resources as well as 

inhibit the development of new supply 

and demand resources. Moreover, many 

regions of the country must make 

investments in the near future to meet 

load growth and, accordingly, studies of 

the most economic means of making 

such investments are critically 

important to consumers. 

549. By expanding the scope of this 

principle, we do not intend to supplant 

the existing process for individual 

customers to integrate new resources or 

loads through specific requests for 


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325E.g., Duke, EEI, ELCON, ISO/RTO Council, 

MISO Transmission Owners, SCE, and Southern. 

326E.g., APPA, Arkansas Commission, PGP, 

Santee Cooper, Southwestern Coop, and 

Sacramento. 

327E.g., E.ON, National Grid and WIRES. 

328E.g., AWEA, NCEMC, NCPA, NRECA, Seattle, 

and TDU Systems. 

interconnection or transmission service 

under the pro forma OATT. Rather, we 

contemplate that any such studies 

conducted pursuant to this principle, as 

explained above, would be for purposes 

of planning for the alleviation of 

congestion through integration of new 

supply and demand resources into the 

regional transmission grid or expanding 

the regional transmission grid in a 

manner that can benefit large numbers 

of customers, such as by evaluating 

transmission upgrades necessary to 

connect major new areas of generation 

resources (such as areas that can 

support substantial wind generation). 

Specific requests for service would 

continue to be studied pursuant to 

existing pro forma OATT processes. 

550. With respect to studying the cost 

of congestion, several transmission 

providers argue that they do not have 

access to information regarding 

generation costs either from their 

merchant function or unaffiliated 

customers. We agree that the 

transmission provider should be 

obligated to study the cost of congestion 

only to the extent it has information to 

do so. We make clear, however, that if 

stakeholders request that a particular 

congested area be studied, they must 

supply relevant data within their 

possession to enable the transmission 

provider to calculate the level of 

congestion costs that is occurring or is 

likely to occur in the near future. To the 

extent that the transmission provider’s 

merchant function possesses such 

information (e.g., redispatch cost 

information), it must provide that 

information to the extent necessary to 

conduct such studies. Providing for 

confidential treatment and application 

of the Standards of Conduct, as 

discussed above, will give assurance to 

customers that their cost and other 

information will not be used 

improperly. To that end, we direct 

transmission providers to clearly define 

the information sharing obligations 

placed on customers in the planning 

attachment to their pro forma OATT. 

551. In response to those commenters 

that argue that regional congestion 

studies should be sufficient, we agree 

that regional congestion studies can be 

used as part of regional transmission 

planning processes required by this 

Final Rule. For example, to the extent 

the DOE has extensively studied 

congestion in certain broad areas, it is 

not necessary or appropriate for 

transmission providers to duplicate 

these studies. However, regional studies 

typically provide broad information on 

overall regional power flows and may 

not provide sufficient detail on local 

system conditions and congestion, such 

as detail on congested local facilities 

that may limit customer supply options, 

or detail on local conditions where 

additional service could be provided 

through redispatch. Moreover, although 

the DOE may identify areas where 

congestion exists or new generation may 

be developed, the purpose of DOE 

congestion studies is not to develop 

specific transmission system plans to 

remedy such congestion or integrate 

such resources. The DOE studies are 

therefore not a substitute for a more 

open and coordinated planning process 

to address specific upgrades that could 

reduce congestion or integrate new 

resources and loads. We therefore 

require each transmission provider to 

comply with the revised economic 

planning studies principle in this Final 

Rule both as to its own transmission 

system and as to the regional planning 

process described above. 

i. Cost Allocation for New Projects 

552. In the NOPR, the Commission 

asked for comment on whether there 

should be a requirement for public 

utilities to develop cost allocation 

principles to address the recovery of 

costs associated with new transmission 

projects. In particular, the Commission 

asked whether the development of 

specific cost allocation principles would 

provide greater certainty and hence 

support the construction of new 

infrastructure or whether cost allocation 

is better handled on a case-by-case 

basis. 

Comments 

553. Several commenters express 

concern that the Final Rule not reopen 

cost allocation principles in RTOs and 

ISOs or in the OATTs of vertically 

integrated transmission providers.325

Duke argues that the Final Rule should 

not address cost allocation for new 

transmission at all, stating that 

transmission pricing should be 

evaluated in a separate proceeding. 

Other commenters agree that cost 

allocation issues should be handled on 

a case-by-case basis.326

554. Some commenters urge the 

Commission to define cost allocation 

principles in this proceeding.327 For 

example, E.ON believes that the cost of 

upgrades should be directly allocated to 

parties benefiting from an expansion 

and proposes that the host transmission 

owner should coordinate and be 

responsible for obtaining funding. Many 

transmission customers, however, 

support rolled-in cost recovery for 

network upgrades.328 TDU Systems ask 

the Commission to clarify that direct 

assignment of facility upgrade costs 

only applies to point-to-point service, 

unless it is being used for the delivery 

of designated network resources to serve 

network load. If direct assignment is 

retained, TDU Systems suggest the 

Commission consider standardizing 

directly assignable facilities on a 

regional basis and stress that the critical 

factor is comparability. TAPS suggests 

‘‘regional’’ cost-spreading for backbone 

high voltage facilities and criticizes 

participant funding because it 

encourages would-be beneficiaries to 

wait and hope that others will step 

forward first. 

555. Old Dominion emphasizes the 

need for cross-border transmission cost 

allocation mechanisms. In joint projects, 

Salt River emphasizes that it is 

inconsistent with an open season 

approach to assign benefits to a party 

and then assign cost responsibility 

beyond what the project participant 

would voluntarily assume based on the 

subscription rights received. Both 

Bonneville and TVA believe that cost 

allocation principles should be based on 

a determination of beneficiaries and cost 

causation. New Mexico Attorney 

General stresses that cost recovery for 

construction of transmission intended 

for wholesale or market transactions 

should not be allocated to native load. 

NCPA states that it would expect some 

Commission deference to recovery of 

costs of projects identified in a truly 

collaborative process. 

556. At the October 12 Technical 

Conference, PJM stated that the 

Commission should provide generic 

guidance on what would be acceptable 

regarding cost allocation, though 

Progress Energy did not favor putting a 

cost allocation approach in the pro 

forma OATT, as modified by the Final 

Rule. National Grid expressed the view 

that the Commission would need to 

address cost allocation generally, 

arguing that cost allocation solely on a 

project-by-project basis is inefficient. 

Commission Determination 

557. The Commission finds, after 

considering the comments, that it is 

appropriate to include a specific 

principle regarding cost allocation. The 

manner in which the costs of new 

transmission are allocated is critical to 

the development of new infrastructure. 

Transmission providers and customers 

cannot be expected to support the 


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329Colorado Interstate Gas Co. v. FPC, 324 U.S. 

581, 589 (1945). 

330See also AWEA, Arkansas Commission, Old 

Dominion, and Project for Sustainable FERC Energy 

Policy. Old Dominion stresses that even in RTOs, 

the transmission owners may have the ability to 

exercise market power and, therefore, the market 

monitoring unit should have the requisite 

independence and authority to investigate and 

address undue influence. 

331E.g., National Grid, PPL, Constellation, and 

Tacoma. 

332E.g., APPA, Bonneville, California 

Commission, Duke, Indianapolis Power, NCEMC, 

NorthWestern, Progress Energy, CREPC, 

Sacramento, Seattle, and TDU Systems. Some 

public power entities, such as APPA, NRECA, and 

TDU Systems are concerned with ensuring that the 

costs of an independent coordinator do not 

outweigh the benefits. 

333TVA believes that the levels of independence 

practiced in NERC and NAESB and the 

implementation and administration of those 

construction of new transmission unless 

they understand who will pay the 

associated costs. We therefore find that, 

for a planning process to comply with 

the Final Rule, it must address the 

allocation of costs of new facilities. 

558. The Commission emphasizes, 

however, that we are not modifying the 

existing mechanisms to allocate costs 

for projects that are constructed by a 

single transmission owner and billed 

under existing rate structures. Our 

intent is not to upset existing cost 

allocation methods applicable to 

specific requests for interconnection or 

transmission service under the pro 

forma OATT. The cost allocation 

principle discussed herein is intended 

to apply to projects that do not fit under 

the existing structure, such as regional 

projects involving several transmission 

owners or economic projects that are 

identified through the study process 

described above, rather than through 

individual requests for service. We will 

not impose a particular allocation 

method for such projects, but rather will 

permit transmission providers and 

stakeholders to determine their own 

specific criteria which best fit their own 

experience and regional needs. The 

proposal should identify the types of 

new projects that are not covered under 

existing cost allocation rules and, 

therefore, would be affected by this cost 

allocation principle. 

559. Although the Commission does 

not prescribe any specific cost 

allocation method in the Final Rule, we 

believe some overall guidance is 

appropriate. Our decisions regarding 

transmission cost allocation reflect the 

premise that ‘‘[a]llocation of costs is not 

a matter for the slide-rule. It involves 

judgment on a myriad of facts. It has no 

claim to an exact science.’’ 329 We 

therefore allow regional flexibility in 

cost allocation and, when considering a 

dispute over cost allocation, exercise 

our judgment by weighing several 

factors. First, we consider whether a 

cost allocation proposal fairly assigns 

costs among participants, including 

those who cause them to be incurred 

and those who otherwise benefit from 

them. Second, we consider whether a 

cost allocation proposal provides 

adequate incentives to construct new 

transmission. Third, we consider 

whether the proposal is generally 

supported by State authorities and 

participants across the region. 

560. These three factors are 

interrelated. For example, a cost 

allocation proposal that has broad 

support across a region is more likely to 

provide adequate incentives to construct 

new infrastructure than one that does 

not. The states, which have primary 

transmission siting authority, may be 

reluctant to site regional transmission 

projects if they believe the costs are not 

being allocated fairly. Similarly, a 

proposal that allocates costs fairly to 

participants who benefit from them is 

more likely to support new investment 

than one that does not. Adequate 

financial support for major new 

transmission projects may not be 

obtained unless costs are assigned fairly 

to those who benefit from the project. 

561. These factors are particularly 

important as applied to the economic 

upgrades discussed above—e.g., 

upgrades to reduce congestion or enable 

groups of customers to access new 

generation. As a general matter, we 

believe that the beneficiaries of any 

such project should agree to support the 

costs of such projects. However, we 

recognize that there are free rider 

problems associated with new 

transmission investment, such that 

customers who do not agree to support 

a particular project may nonetheless 

receive substantial benefits from it. In 

the past, different regions have 

attempted to address such issues in a 

variety of ways, such as by assigning 

transmission rights only to those who 

financially support a project or 

spreading a portion of the cost of certain 

high-voltage projects more broadly than 

the immediate beneficiary/supporters of 

the project. We believe that a range of 

solutions to this problem are available. 

We therefore continue to believe that 

regional solutions that garner the 

support of stakeholders, including 

affected State authorities, are preferable. 

Moreover, it is important that each 

region address these issues up front, at 

least in principle, rather than having 

them relitigated each time a project is 

proposed. Participants seeking to 

support new transmission investment 

need some degree of certainty regarding 

cost allocation to pursue such 

investments. 

3. Additional Issues Relating to 

Planning Reform 

a. Independent Third Party Coordinator 

562. In the NOPR, the Commission 

acknowledged that an independent 

third party coordinator would provide 

benefits for transmission planning, but 

did not propose to require 

independence. Noting that 

independence could take many forms, 

the Commission sought comment on the 

level of independence that could 

provide benefits and the institutions 

that could offer such independence. 

Comments 

563. Overall comments on the use of 

an independent third party to oversee or 

coordinate the planning process range 

from those who believe it is not needed 

to those who feel that it should be 

required rather than merely encouraged. 

Arguing against the need for an 

independent coordinator, South 

Carolina E&G does not believe an 

independent third party is either 

necessary or desirable. Arguing in favor 

of an independent coordinator, EPSA 

strongly supports independent oversight 

and believes that third party oversight 

will be necessary in non-RTO areas, 

particularly where transmission 

providers have conducted nontransparent processes.330 Most 

commenters fall somewhere between 

these two positions, finding potential 

benefits in independence but concurring 

with the proposal not to mandate it. 

564. Several public utility 

commenters acknowledge the potential 

benefits of using an independent 

coordinator and believe the Commission 

should encourage it.331 National Grid, 

for example, finds it difficult to see how 

a non-independent transmission 

provider would be able to manage 

confidential information in a manner 

fair to all stakeholders and recommends 

finding independent administration of 

planning ‘‘superior to’’ nonindependent administration. Other 

commenters note only that 

independence can be beneficial or 

suggest that the Commission be open to 

independent third parties when 

offered.332 Progress agrees there can be 

benefits, but does not believe an 

independent coordinator is needed to 

ensure confidence. 

565. EEI argues against an 

independence requirement, seeing no 

need to require non-RTO/ISO 

transmission providers to engage 

independent third parties to oversee the 

planning process.333 EEI believes the 


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standards by the regional entitities (such as SERC) 

are adequate and appropriate. 

334E.g., American Transmission, Duke, and 

Progress Energy. 

335Similar views are expressed by APPA, 

Arkansas Commission, Bonneville, California 

Commission, NCEMC, NYAPP, and CREPC. 

NYAPP, however, asks the Commission to be 

vigilant in not allowing State commissions 

improper control over the planning process. 

336NYAPP, on the other hand, urges the 

Commission to require planning for all transmission 

facilities, not just bulk power facilities. 

337E.g., AWEA, California Commission, and 

Project for Sustainable FERC Energy Policy. 

planning processes proposed in the 

NOPR are adequate without third party 

oversight and maintains that requiring 

third party coordination could add 

another layer of administration, might 

encroach on State authority, and could 

create the possibility that the 

transmission provider would lose 

control of the transmission plan. EEI 

however also notes that the Commission 

could require independent oversight in 

circumstances where a transmission 

planner has failed to implement the 

principles or has engaged in undue 

discrimination in planning for customer 

needs. 

566. The consensus at the October 12 

Technical Conference was generally 

supportive of the potential benefits of an 

independent facilitator, but not 

supportive of a mandate. There was 

general support for the idea that an 

independent facilitator can assist with 

handling sensitive information and 

provide confidence that analysis of 

information would be fair, although 

several participants stated that sufficient 

trust and confidence could be obtained 

without an independent facilitator. 

Commission Determination 

567. The Commission adopts the 

NOPR proposal to not require the use of 

an independent third party coordinator 

at this time. We agree that there are 

benefits to be gained from independent 

third party oversight, as cited by 

commenters, such as the ability to 

manage confidential information and 

the ability to ensure equitable treatment 

of all viewpoints in planning. We 

therefore encourage transmission 

providers and their customers and other 

stakeholders to explore aspects of 

planning where the use of an 

independent coordinator would be 

beneficial and to incorporate those 

aspects in their planning process 

compliance filings. 

568. It is, however, possible to comply 

with the principles without the use of 

an independent third party. We expect 

the transmission plans themselves to be 

developed under an open process that 

includes coordination among each 

transmission provider, its customers, 

other stakeholders, and its neighbors. A 

transmission provider will need to 

demonstrate to us in a compliance filing 

that the plan meets the principles, 

including providing a dispute resolution 

process. We believe that an open, 

transparent planning process, with 

meaningful coordination and dispute 

resolution, will provide a sufficient 

basis for customers to identify and raise 

meaningful concerns if a plan does not 

treat similarly-situated customers in a 

comparable manner, where planning 

appears to be conducted in a 

discriminatory manner, or in other 

instances where the independence of 

planning may be in question. If disputes 

do arise in these areas and cannot be 

resolved consensually, we are available 

to either encourage a consensual 

resolution (e.g., by use of the Dispute 

Resolution Service) or resolve them 

ourselves if a complaint is filed. 

b. State Commission Participation 

569. In the NOPR, the Commission 

strongly encouraged the participation of 

State commissions and other State 

agencies in the coordinated planning 

process, particularly with regard to 

regional planning. The Commission 

sought comment on how best to 

accommodate effective State 

participation. 

Comments 

570. All commenters addressing the 

question of State participation agree that 

states have an important role in 

transmission planning, but there were 

only limited comments recommending 

specific processes to encourage State 

participation. Supporters of State 

participation generally believe that it 

can assist in obtaining siting approval 

and in cost recovery. ISO/RTO Council 

and individual RTOs and ISOs point to 

their current processes for including 

states in their region in the planning 

process. Noting the local benefits that 

can derive from interstate transmission 

projects, American Transmission 

supports collaborative efforts among 

states such as the Organization of MISO 

States. However, American 

Transmission and other commenters 

suggest that the Commission defer to the 

states to determine how they participate 

in the planning process.334

571. Allegheny believes it should be 

the responsibility of the transmission 

provider to maintain good 

communication with State 

commissions. Nevada Companies assert 

that the real question the Commission 

should be posing is how to coordinate 

the State jurisdictional role in 

transmission planning and construction 

and the obligations imposed by the 

Commission on transmission providers, 

so that the system of coordination does 

not put transmission providers in the 

middle between conflicting State and 

Commission requirements. Moreover, 

Santa Clara notes that some State 

commissions do not represent all energy 

consumers, since they are charged only 

with regulating public utilities, and 

could be conflicted and disinclined to 

act in the best interests of entities not 

under their jurisdiction. 

572. NARUC supports active State 

commission participation in both RTO 

and non-RTO markets.335 NARUC asks 

that the Commission clarify that its 

planning proposals assume that the 

results of State commission planning 

decisions relating to retail load will be 

incorporated into the planning process 

rather than subject to further review. 

NARUC and New Mexico Attorney 

General also ask for clarification that 

joint planning will allow for 

communications between resource and 

transmission planners for the purpose of 

developing State-required resource 

plans and that this will not be 

considered a violation of the Standards 

of Conduct. PNM–TNMP and Southern 

support the NARUC position in their 

reply comments. 

573. New York Commission wants to 

ensure that the Commission’s planning 

responsibilities cover only transmission 

that serves a bulk power system 

function.336 Florida Commission 

believes that it already has direct 

oversight of grid planning and related 

issues, through among other things its 

participation in the FRCC planning 

process and review of the annual Ten 

Year Site Plan. Seattle does not believe 

that any additional requirements are 

needed for State commission 

participation. Other commenters are 

concerned that State policy goals, such 

as California’s Renewable Portfolio 

Standard, be included in the 

coordinated planning required by the 

Final Rule.337 NARUC and California 

Commission also discuss State staff and 

fiscal constraints on participation, and 

California Commission suggests that the 

Commission consider a tariff rider to 

fund State participation. 

Commission Determination 

574. The Commission strongly 

encourages State participation in the 

transmission planning process and 

expects that all transmission providers 

will respect states’ concerns, such as 

retail resource needs, in the planning 


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338As noted above, we expect the concerns of 

NARUC and others that the application of the 

Commission’s Standards of Conduct are inhibiting 

State resource planning will be addressed in the 

rulemaking proceeding on the Standards of Conduct 

in Docket No. RM01–7–000. See supra note 257. 339We also recognize that there are concerns 

about how State regulators and other agencies will 

recover the costs associated with their participation 

in the planning process. As discussed below, we 

direct transmission providers to propose a 

mechanism for cost recovery in their planning 

compliance filings. These proposals should include 

relevant cost recovery for State regulators, to the 

extent requested. 

340E.g., Allegheny, Duke, and National Grid. 

341E.g., APPA, East Texas Cooperatives, Seattle, 

and TDU Systems. 

342E.g., Bonneville, Salt River, PJM, and TVA. 

343E.g., Arkansas Municipal, Project for 

Sustainable FERC Energy Policy, and Southwestern 

Coop. 

344E.g., Duke, Indianapolis Power, MidAmerican, 

Progress Energy, PSEG, South Carolina E&G, and 

SPP. 

process.338 As with any other interested 

stakeholder, we emphasize that 

planning must be coordinated with 

relevant State regulators (including city 

councils, local siting boards, and other 

agencies) that wish to participate in the 

transmission provider’s planning 

process. We will not prescribe a 

particular level of State participation, 

but rather encourage states to determine 

their own level of participation, 

consistent with applicable State law.339

We stress that State determinations with 

respect to retail load will not be secondguessed, but that once those 

determinations are incorporated into the 

transmission plan, the transmission 

planning principles will apply (e.g., for 

purposes of determining whether 

similarly-situated customers are treated 

comparably). 

575. Just as we intend to coordinate 

with State regulators and other agencies, 

we also encourage those parties to 

collaborate amongst themselves as well, 

particularly regionally, in order to reach 

agreement on how best to review and 

approve new transmission facilities that 

are the product of the coordinated and 

regional planning process required by 

this Final Rule. We intend to defer to 

such agreements between State 

regulators and other agencies in a given 

region as appropriate. We are, moreover, 

sensitive to concerns, such as 

Allegheny’s, about the overlapping 

nature of regulatory jurisdiction over 

planning matters. We believe the 

planning principles in this Final Rule 

will help alleviate this concern by 

facilitating coordination through open, 

transparent planning and enhanced 

exchange of information. We also 

understand Santa Clara’s concern that 

certain State regulators do not represent 

all energy consumers in some states; 

however, we do not believe this detracts 

from the significant interest that State 

regulators and other agencies have with 

regard to transmission planning for their 

State and region. 

c. Flexibility in Implementation and 

Examples of Compliant Processes 

576. In the NOPR, the Commission 

sought comment on how much 

flexibility the transmission provider 

should be given in implementing the 

principles and requested examples of 

transmission planning processes that 

comply with the proposed principles. 

Comments 

577. Commenters generally favor 

flexibility and urge the Commission not 

to be too prescriptive regarding how the 

planning processes must satisfy the 

planning principles. Many entities in 

the Western Interconnection cite the 

overall WECC process as largely 

compliant with the principles. Nevada 

Companies notes that the WECC process 

works well under the existing pro forma 

OATT, so that few changes should be 

required to implement the proposal. In 

the East, Progress Energy and Duke cite 

NC Transmission Planning as an 

example of an effective planning 

process that generally meets the 

principles. 

578. Constellation agrees with 

providing flexibility, but believes the 

Commission should strongly encourage 

transmission providers to model their 

compliance filings after existing 

processes, such as those in RTOs and 

ISOs. ISO/RTO Council and all 

individual RTOs and ISOs argue that 

their processes are generally compliant 

and should not be disturbed. 

Transmission providers in RTOs and 

ISOs generally support this position.340

579. Some entities believe that 

flexibility should be permitted in order 

to deal with regional variations, but that 

individual transmission providers 

should have limited flexibility in 

implementing the planning process.341

Some commenters simply state that 

regional flexibility should be permitted, 

without further elaboration.342 Other 

commenters urge the Commission to 

limit both regional and local 

flexibility.343

580. NRG argues that system planning 

models should reflect economic 

dispatch to facilitate efficient utilization 

and also argues in favor of requirements 

for specific criteria on the treatment of 

system overloads and contingencies. 

AWEA proposes a specific regional 

planning protocol patterned off the 

‘‘Collaborative Governance’’ model 

developed during mediation for the 

Southeast RTO in Docket No. RT01–100. 

581. In reply to commenters arguing 

in favor of less flexibility, Indianapolis 

Power maintains that its experience in 

MISO shows that flexibility is needed, 

citing the wide variations within the 

MISO footprint and the difficulties 

experienced in planning for a single 

large region. MidAmerican opposes the 

NRG proposal for regional modeling 

standards, as well as the AWEA 

proposal for a regional planning 

protocol, as too burdensome. Exelon 

expresses general agreement with the 

EEI position on flexibility, but states 

that planning processes outside RTOs 

do not presently meet the NOPR’s 

requirements. Exelon states planning 

processes outside RTOs should follow 

the planning direction of RTOs like 

PJM. 

Commission Determination 

582. Although we allow flexibility in 

the development of a coordinated and 

regional planning process, the 

Commission will carefully review 

transmission planning compliance 

filings to ensure that each planning 

process is consistent with the planning 

principles and other requirements in 

this Final Rule. We encourage 

transmission providers to give 

consideration to existing planning 

processes, such as those already 

implemented by ISOs or RTOs, or those 

proposed by AWEA, as they work with 

their customers and other stakeholders 

to develop a transmission planning 

process that complies with the Final 

Rule. The Commission makes clear, 

however, that we do not endorse any 

specific existing process as a model for 

all transmission providers. 

d. Recovery of Planning Costs 

583. In the NOPR, the Commission 

recognized that participants in the 

planning process must be assured of 

recovery of their costs incurred in the 

planning process, as well as assured that 

the costs will be borne equitably by all 

parties benefiting from the process. The 

Commission also sought comment on 

whether there should be a principle or 

requirement regarding cost recovery and 

allocation associated with funding the 

regional planning requirement. 

Comments 

584. Public utility commenters 

generally support the principle that 

costs should be borne by the 

beneficiaries of the process. EEI agrees, 

but argues that the Commission should 

not establish a specific cost basis for 

recovery, and several other commenters 

concur.344 NorthWestern and PSEG 

support a cost causation principle for 


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345E.g., Southern and South Carolina E&G. 

346E.g., Bonneville, NRECA, and CREPC. 

347E.g., APPA, East Texas Cooperatives Reply, 

FMPA, NCPA, TAPS, TDU Systems, Utah 

Municipals, and WIRES. 

348E.g., Allegheny, American Transmission, 

Constellation, New York Transmission Owners, 

MidAmerican, Duke, EEI, Entergy, FirstEnergy, 

MISO, National Grid, Northeast Utilities, 

NorthWestern, Progress Energy, PSEG, South 

Carolina E&G, SCE, Southern, SPP, Tacoma, 

Tucson, and Xcel. 

349APPA, FMPA, TAPS, and TDU Systems, 

however, point to various sources of authority on 

which the Commission could rely to mandate open 

seasons and joint ownership, such as: To remedy 

undue discrimination under FPA sections 205 and 

206; to carry out FPA section 214(b)(4)’s 

requirement to facilitate the planning and 

expansion of transmission facilities to satisfy the 

needs of load-serving entities; as a condition of 

market-based rate authority, FPA section 203 

approval, or transmission rate incentives under FPA 

section 219; and under the permitting regulations 

promulgated under FPA section 216(c)(2)(B) dealing 

with backstop siting authority. 

350E.g., Bonneville, California Commission, and 

CREPC. Bonneville stresses that any jointly-owned 

facilities should have a single operator. 

351Similar comments were made by APPA, 

Arkansas Commission, FMPA (includes a legal 

analysis in an attachment), NCPA, MISO/PJM 

States, Santa Clara, Southwestern Coop, TANC, and 

TAPS. 

allocation of costs of planning, and 

Southern argues that entities that 

request any transmission sensitivity 

studies should bear the costs of those 

studies. 

585. There is general agreement with 

the principle that costs should be 

recoverable, and some public utilities 

request that the Commission clarify that 

all planning costs not directly assigned 

are recoverable through transmission 

provider transmission rates.345 Other 

commenters believe that the parties in 

the planning process should determine 

how planning costs should be allocated 

and funded. APPA urges simplicity, the 

avoidance of double collecting (e.g., 

LSEs should not have to pay through 

both transmission rates and 

individually) and stresses the need to 

assess costs based on size and assets. 

Other comments are consistent with 

equitable allocation of planning 

costs.346

Commission Determination 

586. We will not propose a specific 

method for recovery and allocation of 

planning costs in this Final Rule. We 

recognize, however, the importance of 

planning cost recovery and will require 

transmission planning processes to 

provide a mechanism for recovery of 

costs. We direct transmission providers 

to work with other participants in the 

planning process, as part of the 

collaborative process described above, 

to develop their cost recovery proposals 

in order to determine whether all 

relevant parties, including State 

agencies, have the ability to recover the 

costs of participating in the planning 

process. Transmission providers should 

also consider whether mechanisms for 

regional cost recovery may be 

appropriate, such as through agreements 

(formal or informal) to incur and 

allocate costs jointly. The Commission 

will consider resulting cost recovery 

proposals, including special riders to 

transmission rates, with an eye toward 

encouraging the broadest participation 

in the planning process possible. 

e. Open Season for Joint Ownership 

587. In the NOPR, the Commission 

expressed its belief that an open season 

to allow market participants to 

participate in joint ownership, 

particularly for large new transmission 

projects, could stimulate grid 

investment and ensure that all 

customers have the ability to participate 

in new projects on a nondiscriminatory 

basis. The Commission sought comment 

on whether to include such a 

requirement and, if so, what conditions 

or limitations should be associated with 

it. 

Comments 

588. As a general matter, a number of 

commenters believe that the planning 

process should include a mandate to 

construct identified upgrades or 

otherwise hold transmission providers 

accountable for carrying out the plan.347

EEI and others argue that such a 

mandate would go beyond planning and 

result in providers giving up control of 

their systems. In their replies, LPPC and 

Sacramento assert that the decision to 

build facilities and to carry out 

transmission plans must rest with 

transmission providers and State 

authorities and that, in any event, it is 

unclear that the Commission has the 

authority to compel construction 

pursuant to regional transmission plans. 

At the October 12 Technical Conference, 

there was considerable discussion of the 

obligation to build and its relationship 

to the planning process proposed in the 

NOPR. 

589. While not necessarily opposed to 

voluntary joint ownership arrangements 

in general, many commenters oppose 

the idea of mandated open seasons.348

EEI provides a representative summary 

of the arguments of those opposed to 

open seasons. First, EEI argues that the 

Commission does not have the authority 

to order joint ownership and that joint 

ownership could interfere with State 

siting authority. It maintains that the 

instances where the Commission can 

order transmission construction are very 

limited and do not extend to the 

authority to order joint ownership.349

Second, EEI argues that joint ownership 

will not provide the benefits cited by 

the Commission, stating that there is 

ample evidence that joint ownership of 

transmission lines is not needed to 

achieve economies of scale in 

construction. In its view, the level of 

transmission investment is currently 

increasing and joint ownership should 

not be expected to create additional 

sources of transmission investment. 

Third, EEI contends that prospective 

joint owners mistakenly believe they 

will not be subject to the same 

requirements as Commissionjurisdictional owners and urge the 

Commission to make clear that both 

jurisdictional and nonjurisdictional 

owners would be subject to the same 

requirements for service over jointlyowned facilities. If the Commission 

were to order joint ownership, Duke 

argues that it must condition such 

ownership by a nonjurisdictional entity 

on that entity filing a safe harbor OATT 

ensuring reciprocal open access by that 

joint owner. 

590. Tacoma notes that ColumbiaGrid 

includes a mechanism for small users to 

participate in transmission projects in 

the proposal it is considering for its 

planning process. Xcel supports 

adopting the open season concept as an 

option in joint planning requirements. 

Though it does not completely oppose 

the principle, MidAmerican sees 

significant practical problems in 

developing and implementing an open 

season proposal and regards the open 

season idea as premature. Others 

generally support allowing for open 

seasons and joint ownership, but also do 

not believe they should be mandated.350

591. A number of other commenters, 

however, support requiring open 

seasons as a method of ensuring that 

identified upgrades are constructed. 

ELCON is strongly in favor, stating that 

open seasons for joint ownership is an 

‘‘idea whose time has come’’ and 

expressing frustration that the 

Commission has not already acted on 

this proposal. FMPA argues that joint 

ownership will aid in providing 

additional capital for transmission 

projects. TDU Systems urge the 

Commission to require transmission 

providers, including RTOs and ISOs, to 

hold open seasons.351 Joined by 

Arkansas Commission, TDU Systems 

argue that open seasons should not be 

limited to large projects. PGP supports 

open seasons when providers do not 

voluntarily agree to add capacity based 

on the results of the transmission plan. 

TDU Systems cite the Neptune and 


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352As the Commission stated in Order No. 679–

A, ‘‘[t]he Commission will look favorably on 

incentive requests that include public power joint 

ownership.’’ Order No. 679–A at P 102. 

353E.g., EEI, MISO, NorthWestern, PSEG, and 

Tacoma. 

354Related to this, California Commission asserts 

that regional planning processes need to be closely 

linked with the resource adequacy planning 

processes and renewable energy portfolio standards 

on the State level. 

355EEI replies in opposition to TAPS’ assertions 

that planning should address transmission for 

potential resources, arguing that such a requirement 

would be cost prohibitive and would harm users. 

356E.g., APPA, Arkansas Commission, AWEA, 

CREPC, Sacramento, and Seattle. 

Cross-Sound Cable projects, where 

regulated utilities failed to provide 

solutions despite the need for expansion 

of the system in those regions. Seattle 

argues that voluntary joint ownership of 

projects should not be contingent upon 

an open season requirement. TANC 

points to current joint ownership 

arrangements in the Western 

Interconnection. Sacramento likewise 

notes that the joint planning and 

ownership process in the Western 

Interconnection has been a success, but 

asks the Commission to make clear that 

physical rights set asides are available 

in CAISO to accommodate non-LMP coowners. 

592. On reply, EEI, Entergy, and 

Southern repeat arguments against joint 

ownership and open seasons. EEI 

replies that FMPA’s claim that joint 

ownership will result in increased 

investment is not based on fact and will 

not increase access. In its reply, TDU 

Systems states that joint ownership 

would not, as argued by EEI, infringe on 

State siting, as states would retain this 

authority over the jointly-developed 

project. APPA also stresses that its 

members have fewer difficulties 

obtaining service where joint ownership 

is permitted. In their replies, Lassen, 

Santa Clara, and TANC argue that the 

Commission should not, as suggested by 

Duke, condition the participation of a 

nonjurisdictional entity in a jointlyowned project on that entity filing a safe 

harbor OATT, as public power entities 

use the capacity they need and sell the 

rest whether or not they have a safe 

harbor OATT on file. However, TAPS 

asks on reply that access to jointlyowned facilities be available through a 

pro forma OATT. Participants at the 

October 12 Technical Conference 

expressed both support for joint 

ownership, as well as caution. National 

Grid states that it has had good success 

with joint ownership, but that jointlyowned projects are more complicated 

and can take longer to develop. 

Commission Determination 

593. The Commission believes there 

are benefits to joint ownership of 

transmission facilities, particularly large 

backbone facilities, both in terms of 

increasing opportunities for investment 

in the transmission grid, as well as 

ensuring nondiscriminatory access to 

the transmission grid by transmission 

customers. The comments received in 

response to the NOPR support the 

notion that joint ownership can provide 

these benefits in many cases. For 

example, as TDU Systems note, the 

Neptune and Cross-Sound Cable 

projects have resulted in significant 

amounts of new transmission capacity 

in regions facing chronic constraints. 

We encourage joint ownership for other 

large backbone transmission upgrades 

included in the transmission plan 

developed by the planning process 

required by this Final Rule.352

594. We acknowledge, however, that 

joint ownership can increase the 

complexity of planning and developing 

a transmission project and are sensitive 

to concerns that formal open seasons 

can add to that complexity. We 

therefore do not mandate open season 

procedures to allow market participants 

to participate in joint ownership. We 

recognize that there may be reasons, 

given the complexity of the 

transmission grid and changing 

conditions of supply and demand for 

power, why any given facility identified 

in a transmission plan may not 

ultimately be constructed. 

Consequently, our planning reforms do 

not include an obligation to construct 

each facility identified in the plan, 

whether individually or through joint 

ownership mechanisms. At the same 

time, the Commission agrees that joint 

ownership may be useful in certain 

situations and encourages transmission 

providers and customers alike to 

consider the use of open seasons to 

realize construction of upgrades 

identified in the planning studies. If a 

transmission provider declines to 

construct an identified upgrade, we also 

encourage customers and third parties 

to consider, either individually or 

jointly, development and ownership of 

a project to the extent consistent with 

applicable State law. 

f. Specific Study Processes Beyond 

Reliability and Congestion Reduction 

595. In the NOPR, the Commission 

sought comment on whether there 

should be a specific study process to 

identify opportunities to enhance the 

grid for purposes beyond maintaining 

reliability or reducing current 

congestion. Such a study process could 

allow interested entities, including State 

resource agencies and others, to request 

the transmission provider to model grid 

upgrades needed to accommodate the 

construction of new resources and 

provide information needed to 

proactively evaluate such resources. The 

Commission expected that such studies 

would not conflict with State 

prerogatives, but rather would provide 

states with better information to 

evaluate all relevant resource options. 

Comments 

596. Most transmission provider 

commenters favor providing for study of 

some grid enhancement beyond 

reliability and congestion-related needs, 

but believe the Final Rule should not 

mandate a specific study process. 

Various commenters argue that the 

Commission should allow planning 

participants to determine details such as 

the scope, number, and cost 

responsibility for the studies.353 MISO 

states that it is working on these issues, 

but enhancement beyond maintaining 

reliability or reducing congestion is a 

complicated subject best left to each 

RTO or ISO to decide. 

597. Some commenters are more 

explicit or expansive in their 

recommendations. CAISO recommends 

that the Commission develop a policy to 

encourage construction of transmission 

lines necessary to connect renewable 

resources,354 and Suez Energy NA 

provides similar comments about new 

remote generation. PJM believes the 

planning process should look at future 

congestion and building for resources 

not yet announced. The New Jersey 

Board believes that demand-side 

management and other solutions, such 

as distributed renewable generation, 

also should be considered. WIRES and 

ELCON believe all credible proposals 

should be studied. TAPS asserts that 

planning should study grid 

enhancements needed for new potential 

resources.355 These views are consistent 

with the views of many of the 

commenters that support additional 

study processes.356 TDU Systems, 

however, point out that planning for 

reliability and economics should be 

incorporated into the open and 

inclusive planning process and, 

therefore, a special study process should 

not be needed. 

598. Other commenters are opposed 

to additional processes: South Carolina 

E&G does not see a need for additional 

studies; Southern believes additional 

study processes would be overly 

burdensome and would divert attention 

away from the fundamentals of prudent 

planning; and Bonneville notes that 

market participants often make requests 


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357E.g., New Jersey Board, Ohio Power Siting 

Board, and WIRES. 

358E.g., APPA, NRECA, Old Dominion, and 

Seattle. APPA also suggests OASIS posting. 

359E.g., Arkansas Municipal, AWEA, FMPA, and 

TDU Systems. 

360E.g., Arkansas Municipal, TAPS, and TDU 

Systems. 

for expensive studies without following 

through on them. Santee Cooper 

cautions the Commission against giving 

license to those who would attempt to 

hijack the regional planning process in 

order to advance a generation-related 

agenda, and notes that the 

Commission’s authority does not extend 

to generation resource adequacy. 

Commission Determination 

599. We believe that development of 

a study process for identifying 

opportunities for grid enhancement 

beyond reliability and congestion 

reduction has the potential to provide 

useful information and would generally 

benefit development of the transmission 

grid. We therefore will include such 

study processes within the scope of 

Principle No. 8. In the NOPR, that 

principle concerned only congestion 

studies, but, as modified above, it now 

includes studies regarding upgrades that 

could integrate new generation 

resources. We note that various 

commenters argued for the 

consideration of demand resources in 

development of enhancements to the 

transmission grid.357 As we explain 

above, consideration of such resources 

falls within Principle No. 8, as modified 

by the Final Rule. 

g. Level of Detail in the OATT 

600. In the NOPR, the Commission 

sought comment on the level of detail to 

be required to be in the transmission 

provider’s OATT regarding its planning 

process. 

Comments 

601. Several commenters argued that 

the details of the planning process 

should be included in the transmission 

providers’ OATTs.358 Seattle noted that 

the OATT should balance the need for 

detailed planning requirements with the 

need for regional processes to evolve. 

Commission Determination 

602. The Commission agrees that the 

transmission planning attachment to a 

transmission provider’s OATT must 

include sufficient detail to enable 

transmission customers to understand 

the transmission provider’s planning 

process. This new attachment must 

therefore include: 

(a) The process for consulting with 

customers and neighboring transmission 

providers; 

(b) The notice procedures and 

anticipated frequency of meetings or 

planning-related communications; 

(c) A written description of the 

methodology, criteria, and processes 

used to develop transmission plans; 

(d) The method of disclosure of 

transmission plans and related studies 

and the criteria, assumptions and data 

underlying those plans and studies; 

(e) The obligations of and methods for 

customers to submit data to the 

transmission provider; 

(f) The dispute resolution process; 

(g) The transmission provider’s study 

procedures for economic upgrades to 

address congestion or the integration of 

new resources; and 

(h) the relevant cost allocation 

procedures or principles. 

C. Transmission Pricing 

1. General 

603. As the Commission explained in 

Order No. 888, the pro forma OATT was 

designed to include primarily non-rate 

terms and conditions of open access 

non-discriminatory transmission 

service. Transmission providers first 

were required to adopt the non-rate 

terms and conditions of the pro forma 

OATT and then, in a subsequent filing 

under FPA section 205, to propose 

corresponding rates for service provided 

under their OATTs. Consistent with the 

focus of Order No. 888 on the non-rate 

terms and conditions of open access, the 

Commission did not propose broad 

reform of transmission pricing policy 

through the NOPR. Rather, the 

Commission identified in the NOPR 

several discrete pricing rules that it 

considered part and parcel of OATT 

service that merit reform, which we 

discuss in more detail later in this 

section. The Commission also 

specifically noted in the NOPR that the 

purpose of this rulemaking is to 

strengthen the pro forma OATT to 

remedy undue discrimination and not to 

create new market structures. 

604. Despite the clear scope of this 

rulemaking, several commenters 

contend that broader ratemaking 

reforms should be implemented in order 

to remove obstacles to achieving 

competitive markets. Various 

commenters assert that rate pancaking 

must be eliminated in this reform, 

noting that the Commission has 

recognized in the past that pancaked 

rates inhibit the development of 

competitive markets.359 Arkansas 

Municipal and TDU Systems contend 

that pancaked rates are particularly 

burdensome for customers with loads 

and resources on multiple transmission 

providers systems and those that sit 

essentially at or on the boundaries. TDU 

Systems argue that the failure to 

eliminate pancaked rates has caused 

many of the TDU Systems to spend 

many millions of dollars to build 

transmission from generation to 

interconnect with multiple control areas 

in order to avoid paying multiple 

wheeling charges. 

605. Some of these commenters also 

advocate that the Commission should 

move towards joint rates.360 Arkansas 

Municipal Power argues that moving 

toward joint rates outside an RTO will 

not only eliminate competitive barriers 

outside RTOs, but would reduce the 

disincentive to formation of new and 

expanded RTOs. TAPS complains that 

the NOPR requires regional planning, 

but has no provision requiring 

transmission providers to build facilities 

to support regional needs, arguing that 

joint rates would ease this problem. 

TDU Systems argue, however, that any 

joint rate methodology should not shift 

costs to other network customers, 

especially where surcharges are sought 

that might open the door to potential 

over-recovery by transmission providers 

as argued in the PJM/MISO proceedings. 

Old Dominion also contends that the 

Commission should add a requirement 

in the pro forma OATT that regional 

transmission costs be recovered through 

a single regional transmission rate of a 

rolled-in nature. Relative to cost 

recovery, Old Dominion believes that 

rolled-in zonal rates work for local 

facilities within a single transmission 

owner footprint, but regional rolled-in 

rates would be necessary for larger 

footprints. 

606. Old Dominion also contends that 

the lack of periodic review by the 

Commission of stated transmission rates 

sends a strong economic signal to 

transmission owners to not invest in 

new transmission. Old Dominion argues 

that the Commission should require 

periodic rate reviews at least every five 

years or implement formula rates which 

would remove economic incentives for 

failing to build transmission. 

607. EEI argues that the Commission 

should not address in this proceeding 

TDU Systems’ proposal to require 

transmission providers to eliminate 

pancaked transmission rates in nonRTO regions because it involves 

complex issues that are not easily 

resolved. EEI contends that transmission 

providers should not be required to 

eliminate multiple transmission rates 

across multiple systems simply to allow 

TDU members to avoid the economic 

consequences of their decisions to 


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361E.g., Chandley-Hogan, Constellation, and PJM. 

362E.g., Morgan Stanley and Steel Manufacturers 

Associations. 

363E.g., Chandley-Hogan and PJM. 

364E.g., EPSA and Chandley-Hogan. 

purchase energy from off-system 

resources. 

608. Other commenters ask the 

Commission to institute much broader 

market reforms in this rulemaking, 

arguing that the Commission will not be 

able to achieve its objectives of 

remedying undue discrimination and 

developing competitive wholesale 

markets without a fundamental change 

in market structures. Several 

commenters advocate changing the 

market structure in non-RTO markets to 

allow transmission customers to access 

the transmission provider’s dispatch 

and redispatch options.361 Some 

commenters 362 go further to assert that 

the Commission require the use of 

locational marginal pricing (LMP) as a 

part of OATT reform. Other 

commenters 363 assert that the 

Commission would not need to adopt a 

full RTO market design to achieve its 

more limited objectives, but contend 

that eliminating the fundamental 

inconsistency between the OATT rules 

and actual operation of the grid would 

remove a major obstacle to other 

reforms. Several commenters 364

contend that requiring use of a security 

constrained economic dispatch is a 

needed part of this reform. 

609. Chandley-Hogan contend that the 

key element to ensuring transmission 

services are provided on a just, 

reasonable and not unduly 

discriminatory basis is to provide open 

access to the security constrained 

economic dispatch and the associated 

imbalance pricing that arises from that 

dispatch. Chandley-Hogan state that 

using a security constrained economic 

dispatch would also substantially 

reduce the problems inherent in the pro 

forma OATT’s reliance on contract 

paths and ATC for transmission service 

scheduling. 

610. Chandley-Hogan contend that a 

viable path to Order No. 888 reform is 

to start from the premise that open 

access to the dispatch (and redispatch) 

and marginal cost pricing for 

imbalances and redispatch to 

accommodate transmission are keys to 

getting open, non-discriminatory access 

to transmission. Chandley-Hogan argue 

that dispatch is the essential 

transmission service and providing 

open access to this dispatch is a path to 

achieving open, non-discriminatory 

access to transmission. Chandley-Hogan 

contend that a third party cannot 

effectively access the grid without 

accessing and closely interacting with 

the system operator’s dispatch, 

including determining if transmission 

service is available, acquiring redispatch 

service to allow its schedule to proceed 

without curtailment, and settling 

imbalances from scheduled levels. 

Williams agrees with Chandley-Hogan 

that a system allowing non-RTO utilities 

to deny and curtail service requests 

whenever there is little ATC left and 

without offering redispatch to a third 

party is completely flawed. Williams 

argues that these same requests would 

be accommodated in an RTO through 

redispatch as long as the RTO has 

sufficient offers to arrange a security 

constrained economic dispatch. 

611. EPSA argues on reply that an allinclusive, ‘‘asset-blind’’ administration 

of open dispatch is needed to fully 

eliminate undue discrimination. EPSA 

states that security constrained dispatch 

will provide reliable operation and 

efficient utilization of the transmission 

grid by promoting the use of newer, 

cleaner and less expensive power 

plants. EPSA urges that these issues 

should be explored further here or in 

another policy proceeding. Project for 

Sustainable FERC Energy Policy asserts 

that there is no assurance of nondiscriminatory access to transmission 

services and competitive wholesale 

markets unless load and potential 

competitors of the control area operators 

are treated comparably during dispatch. 

Project for Sustainable FERC Energy 

Policy supports additional provisions to 

the pro forma OATT requiring 

transparency and fairness in system 

dispatch and redispatch such as either 

an ‘‘open dispatch’’ requirement or a 

rule-based framework with standards of 

conduct and OASIS disclosure, as well 

as reporting and auditing requirement to 

eliminate anticompetitive incentives. 

Project for Sustainable FERC Energy 

Policy argues that sufficient data to 

establish marginal system costs and 

permit comparisons with the prices/ 

costs of neighboring systems should be 

disclosed on OASIS. 

612. PJM proposes open dispatch 

consisting of control of the dispatch 

function by a disinterested entity and 

the institution of a spot or balancing 

market to allow for the formation of 

real-time prices. Project for Sustainable 

FERC Energy Policy encourages the 

further separation of the system 

operator’s dispatch functions from its 

merchant functions, to include specific 

dispatch transparency and 

comparability mandates as per PJM’s 

and Transparent Dispatch Advocates’

request. Project for Sustainable FERC 

Energy Policy supports comparable 

dispatch services through an 

independent entity. In its reply 

comments, Williams supports the rules 

based dispatch service proposed by PJM 

and states that it will reduce the 

opportunity for transmission providers 

to levy unjust and unreasonable 

redispatch rates. 

613. PJM also contends that non-RTO/ 

ISO systems have negative impacts on 

RTO systems because of the respective 

treatment of import transactions by nonRTOs/ISOs and RTOs/ISOs and the 

incidence of loop flows in market 

environments. PJM argues that entities 

scheduling flows through PJM that 

actually loop onto other systems 

nevertheless benefit financially because 

they collect the difference between the 

relatively high price at the interface 

where the energy is scheduled to enter 

the PJM footprint and the lower price at 

the interface where the energy is 

scheduled to leave the PJM footprint. 

When energy does not flow as 

scheduled, PJM states that the otherwise 

expected, beneficial impact on the 

transmission constraints are not 

realized, resulting in price differentials 

between the affected interfaces. As a 

result, PJM contends that such 

scheduled transactions only contribute 

to the FTR revenue adequacy issues PJM 

has experienced over the last 12 

months. 

614. PJM asserts that it is unduly 

preferential for a non-RTO/ISO utility to 

take advantage of the benefits of the 

organized markets of a bordering RTO/ 

ISO without any obligation to bear any 

of the costs of administering those 

markets. PJM contends that it is unduly 

discriminatory and an impediment to 

the development of competitive markets 

to permit a non-RTO/ISO utility 

adjacent to an RTO/ISO’s organized, 

transparent markets to accept the 

benefits of those markets and the 

regional transmission planning process 

that sustains them, while the same 

utility relies on non-market-based 

congestion management and limits the 

access of its competitors, including 

those who are members of the relevant 

RTO/ISO, to its dispatch sequence and 

wholesale prices within its service area. 

PJM asks the Commission to declare that 

it would not be unduly discriminatory 

for an RTO/ISO to include in its tariff 

a provision that makes an external 

system operator’s access to those 

markets contingent on the external 

operator providing reciprocal access to 

its dispatch and planning functions for 

RTO/ISO members, as well as access to 

the external system’s real-time marginal 

system cost information. 

615. Transparent Dispatch Advocates 

propose on reply that the Commission 

require the industry to develop interVerDate Aug<31>2005 18:17 Mar 14, 2007 Jkt 211001 PO 00000 Frm 00078 Fmt 4701 Sfmt 4700 E:\FR\FM\15MRR2.SGM 15MRR2

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365E.g., LPPC, Entergy, and Sacramento. 

control area coordination agreements to 

provide for reciprocal redispatch to 

alleviate constraints at specified border 

flowgates. Transparent Dispatch 

Advocates argue that redispatch over a 

larger area provides transmission 

providers more options to extract the 

full efficiency of their systems by 

allowing import/export transactions and 

intra-control area flows to continue that 

would otherwise be curtailed by 

providing redispatch of generation 

across a border at a lower cost than 

would result had the transaction been 

curtailed. Transparent Dispatch 

Advocates further propose that the 

Commission establish principles in the 

Final Rule to guide the development of 

these coordination agreements and 

require filing of the agreements within 

12 months of the issuance of the Final 

Rule. Transparent Dispatch Advocates 

suggest that technical conferences may 

need to be scheduled to address any 

utility specific issues that arise. 

616. Morgan Stanley and Steel 

Manufacturers Association contend that 

every control area should be moving 

toward LMP and that facing an 

imbalance cost measured by full 

replacement value of redispatch 

measured under LMP is the correct 

incentive to follow a schedule. Entegra 

similarly argues that customers and 

State regulators would benefit from 

more transparency regarding congestion 

on the transmission system and that the 

most efficient way to provide this 

transparency is to require transmission 

providers to apply LMP models to their 

systems and to post the resulting 

modeled LMPs. 

617. Several commenters object to the 

proposal for a mandatory all-inclusive 

redispatch using bid-based pricing.365

These commenters generally argue that 

such a proposal could not lawfully be 

adopted in the Final Rule because it 

dramatically departs from the scope of 

the NOPR. They also argue that the 

proposal is bad policy because there is 

no record showing that consumers 

would benefit from the costly and 

disruptive implementation required for 

the proposal and that adoption of the 

proposal would create controversy given 

that Congress and the Commission have 

already rejected an LMP-based model of 

industry restructuring. Sacramento adds 

that given the record of transmission 

investment in RTOs, open redispatch 

might not meet the transmission 

expansion goals of the NOPR. 

618. Southern argues on reply that 

there is no legal basis for claims that a 

lack of open dispatch results in undue 

discrimination. Southern states that the 

entities at issue are not similarly 

situated and that open dispatch 

concerns resource procurement, an area 

beyond the scope of the Commission’s 

jurisdiction. Southern further argues 

that the open dispatch remedy proposed 

by PJM and others would require radical 

restructuring and market reforms that 

are unfounded, lack a legal basis and 

would result in political discord. 

Southern states that open dispatch 

would violate FPA section 217 by 

threatening the ability of LSEs to 

maintain access to transmission rights to 

serve native load. In its reply comments, 

Entergy states that the open dispatch 

proposal should be rejected because it is 

unnecessary to ensure open access 

transmission service, is contrary to the 

Congressional intent in passing EPAct 

2005, exceeds the scope of the 

Commission’s jurisdiction by overriding 

State jurisdiction over sales to retail 

customers, and would result in 

opposition that will delay other reforms 

and distract the Commission with 

divisive litigation. 

619. Sacramento states that the 

proposals for mandatory redispatch, the 

control of the dispatch by a 

disinterested entity, and the institution 

of a spot or balancing market to allow 

for the formation of real-time prices 

would undermine customers’ objectives 

to receive uninterrupted transmission 

service at a predictable price and ignore 

transmission system operational 

limitations. Sacramento states that the 

value of mandatory redispatch in the 

Western Grid is limited because 

constraints often overlap and change 

from thermal to voltage to stability 

constraints at differing load levels and 

redispatching large amounts of 

generation to relieve constraints because 

of the distance between loads and 

generation cannot be achieved in the 

timeframes required to maintain 

reliability. Sacramento is concerned that 

PJM’s proposal would cause 

appropriation of generation built to 

serve a transmission provider’s native 

load in order to effectuate third-party 

transmission transactions, strain the 

transmission provider’s grid, and cause 

additional curtailment of native load 

and firm transactions when a force 

majeure event occurs. 

620. Entergy cites the approval of the 

ICT proposal as ample evidence that the 

incremental approach proposed in the 

NOPR is a better means of improving 

clarity, transparency and improvements 

in dispatch efficiency than the 

Transparent Dispatch Advocates and 

PJM seek to mandate. Entergy states that 

the arguments posed by PJM and 

Chandley-Hogan do not target 

remedying discrimination or ensuring 

comparability, but rather focus on what 

they believe are mechanisms for more 

efficient use of the grid. Overall, Entergy 

does not support any changes to the 

basic nature of the services available 

under the pro forma OATT or the 

development of real-time markets to 

ensure comparable access. 

621. In its reply comments, 

Sacramento disagrees with PJM’s claims 

that TLRs are a discriminatory 

substitute for real-time redispatch and 

PJM’s proposal to eliminate such use of 

TLRs in favor of an expanded redispatch 

obligation. Sacramento argues that firm 

customers under the pro forma OATT 

do not expect TLRs, while those in Day 

2 RTOs expect that generation will be 

redispatched. Sacramento adds that 

TLRs affect all loads, but that the nature 

of firm physical rights service is that it 

will not be interrupted except in very 

narrow defined circumstances. 

622. Southern argues that customers 

selling between RTO and non-RTO 

systems are treated equally since part of 

the transaction is under an LMP 

treatment and the other part is under 

OATT treatment. In response to PJM’s 

allegations that loop flows are unduly 

discriminatory to its customers, 

Southern states that loop flows are 

unavoidable consequences of integrating 

electrical systems and that PJM itself 

imposes loop flows on non-RTO 

systems, the effects of which are not 

compensated by PJM. If PJM believes 

that entities are free-riding on its system 

or manipulating its system, Southern 

argues that PJM could seek to increase 

market participation charges or file a 

complaint with the Commission. 

Sacramento agrees that this rulemaking 

is the wrong forum for resolving seams 

issues given the stated scope of the 

NOPR. Sacramento adds that border 

utilities do not ‘‘free ride’’ on RTO 

markets because these markets impose 

significant costs on border entities. 

Sacramento also disagrees that open 

redispatch would resolve loop flow 

problems and suggests other mechanism 

for addressing loop flow. Finally, 

Sacramento states that TLRs are an 

Eastern Interconnection process that, 

although rare, occur in RTOs and nonRTO areas. 

Commission Determination 

623. As the Commission explained in 

the NOPR, we do not intend to 

undertake a comprehensive overhaul of 

our transmission pricing policies in this 

rulemaking. Instead, the Commission 

proposed a number of specific reforms 

to discrete provisions in the pro forma 

OATT and a clarification to our ‘‘higher 

of’’ policy for pricing of transmission 

system expansions. Given the limited 


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366See, e.g., RTO Border Utility Issues, Notice of 

Technical Conference on Seams Issues for RTOs 

and ISOs in the Eastern Interconnections, (Docket 

No. AD06–9–000) (issued Jan. 25, 2007). 

367 Id. 

368Order No. 888 at 31,703. 

369 Id. 

370See Id. at 31,960. 

371Order No. 888–A at 30,230. 

372 Id. 

373 Id. at 30,232. 

374 Id. at 30,229. 

375 Id. The Commission further stated that the pro 

forma OATT permits schedule changes up to 

twenty minutes before the hour at no charge, and 

that it would allow the transmission provider and 

the customer to negotiate and file another deviation 

band more flexible to the customer, if the same 

deviation band is made available on a not unduly 

discriminatory basis. Id. at 30,232–33. 

376 Id. at 30,234 

377 Id. 

378See, e.g., Arizona Public Service Co., FERC 

Electric Tariff, Twelfth Revised Volume No. 2, 

Schedule 4 (Energy Imbalance Charge), accepted in 

Arizona Public Service Co., Docket No. ER04–442–

003 (Sep. 30, 2004) (unpublished letter order); 

Public Service Company of New Mexico, FERC 

Electric Tariff, Second Revised Volume No. 4., 

Schedule 4 (Energy Imbalance Charge), accepted in 

Public Service Co. of New Mexico, Docket No. 

ER04–416–002 (Sep. 30, 2004) (unpublished letter 

order). 

379See Idaho Power Co., 102 FERC ¶ 61,351 

(2003); Duke Electric Transmission FERC Electric 

Tariff, Third Revised Volume 4, Original Sheet No. 

120 accepted in Duke Energy Corp., Docket No. 

ER04–812–001 (Jul. 2, 2004) (unpublished letter 

order). 

380Order No. 888–A at 30,230. 

scope of this proceeding, we do not 

believe it would be appropriate to adopt 

the broader ratemaking proposals 

suggested by commenters. Issues of rate 

pancaking, including joint rates, 

regional rolled-in rates and rate reviews 

are beyond the scope of this proceeding. 

624. Similarly, the Commission made 

clear in the NOPR that the purpose of 

the proposed rule is to strengthen the 

pro forma OATT to remedy undue 

discrimination and not to impose any 

particular market structure on the 

industry. The Commission’s focus in 

this proceeding was and remains the 

development of competitive wholesale 

markets through the reduction of 

barriers to entry created through the 

control of transmission assets. We 

continue to believe that the appropriate 

focus of this rulemaking is to strengthen 

competitive wholesale markets by 

adopting reforms to address remaining 

areas of undue discrimination and 

issues of comparability rather than 

mandating a fundamental change in the 

market structure. 

625. We therefore reject requests to 

institute systems that require the realtime use of regional security constrained 

economic dispatch and LMP for 

granting real-time transmission service 

and for the settlement of imbalances or 

to otherwise require transmission 

providers to use LMP-based modeling. 

We believe that LMP market designs can 

provide significant benefits to customers 

through more efficient use of the grid, 

but do not believe that such market 

designs are the only way to remedy 

undue discrimination or achieve 

comparability. We continue to support 

regional flexibility in market 

development, provided that the market 

design implemented by the transmission 

providers provides other transmission 

customers with comparable service to 

that which the transmission providers 

provide to their own native loads and 

affiliates. 

626. We also reject arguments 

regarding seams issues creating an 

undue discrimination between market 

and non-market areas that must be 

resolved in this proceeding. We note 

that there are currently processes 

underway to address seams issues both 

in the Eastern and Western 

Interconnections.366 We believe that 

such seams issues are beyond the scope 

of this rule and are better addressed on 

a case-by-case basis or, as appropriate, 

in the proceeding on RTO Border Utility 

Issues.367

2. Energy and Generation Imbalances 

627. In Order No. 888, the 

Commission concluded that six 

ancillary services must be included in 

an OATT.368 One of those ancillary 

services is energy imbalance service 

under Schedule 4 of the pro forma 

OATT.369 Energy imbalance service is 

provided when the transmission 

provider makes up for any difference 

that occurs over a single hour between 

the scheduled and the actual delivery of 

energy to a load located within its 

control area.370 The Commission 

recognized, in general, that the amount 

of energy taken by load in an hour is 

variable and not subject to the control 

of either a wholesale seller or a 

wholesale requirements buyer.371

628. The Commission found that 

energy imbalance service should have 

an energy deviation band appropriate 

for load variations and a price for 

exceeding the deviation band that is 

appropriate for excessive load 

variations.372 The Commission 

established an hourly deviation band of 

+/¥1.5 percent (with a minimum of 2 

MW) for energy imbalance. The 

Commission explained that this 

deviation band promotes good 

scheduling practices by transmission 

customers, which ensures that the 

implementation of one scheduled 

transaction does not overly burden 

another.373

629. With respect to compensation 

associated with the hourly energy 

deviation band, the Commission 

explained that, for energy imbalances 

within the deviation band, the 

transmission customer may make up the 

difference within 30 days (or other 

reasonable period generally accepted in 

the region) by adjusting its energy 

deliveries to eliminate the imbalance 

(i.e., return energy in kind within 30 

days).374 In addition, the Commission 

explained that the transmission 

customer must compensate the 

transmission provider for each 

imbalance that exceeds the hourly 

deviation band and for accumulated 

minor imbalances that are not made-up 

within 30 days.375 With respect to the 

price of energy imbalance service, the 

Commission explained that it 

intentionally did not provide detailed 

pricing requirements.376 Instead, the 

Commission required transmission 

providers to propose rates for energy 

imbalance service.377

630. Although transmission providers 

have different energy imbalance 

charges, they typically require 

customers to correct energy imbalances 

within the deviation band through 

return in kind or a financial settlement 

that requires payment for 

underdeliveries of energy equal to 100 

percent of the transmission provider’s 

system incremental cost for the hour the 

deviation occurred. For energy 

overdeliveries, the transmission 

customer would receive a payment 

equal to 100 percent of the transmission 

provider’s decremental cost for the hour 

the deviation occurred.378 Outside the 

deviation band, transmission providers 

either charge the transmission customer 

(1) A percentage of the utility’s system 

cost, such as 110 percent of incremental 

costs for underscheduling or 90 percent 

of decremental costs for overscheduling 

or (2) the greater of a percentage of 

system costs or a fixed charge, such as 

$100 per MWh.379

631. While the Commission found in 

Order No. 888 that energy imbalance 

was an ancillary service, it also 

recognized that another imbalance may 

arise for differences between energy 

scheduled for delivery from a generator 

and the amount of energy actually 

generated in an hour,380 commonly 

called generator imbalance. The 

Commission concluded, however, that a 

generator should be able to deliver its 

scheduled hourly energy with precision 

and expressed concern that allowing a 

generator to deviate from its schedule by 

1.5 percent without penalty, so long as 


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381 Id. 382 Id. 383See, e.g., Niagara Mohawk Power Corp., 86 

FERC ¶ 61,009, order on reh’g, 87 FERC ¶ 61,148 

(1999) (Niagara Mohawk); PacifiCorp, 95 FERC 

¶ 61,145, order on reh’g and clarification, 95 FERC 

¶ 61,467 (2001); Alliant Energy Corporate Services, 

Inc., 93 FERC ¶ 61,340 (2000); Wolverine Power 

Supply Coop., 93 FERC ¶ 61,330 (2000); 

Commonwealth Edison Co., 93 FERC ¶ 61,021 

(2000); FirstEnergy Operating Cos., 93 FERC 

¶ 61,200 (2000), order denying reh’g & granting 

clarification, 94 FERC ¶ 61,184 (2001); Tampa 

Electric Co., 90 FERC ¶ 61,330 (2000), reh’g denied, 

95 FERC ¶ 61,101 (2001); Florida Power Corp., 89 

FERC ¶ 61,263 (1999); Consumers Energy Co., 87 

FERC ¶ 61,170 (1999) (Consumers). 

384Order No. 2003–B at P 74–75. 

385 Imbalance Provisions for Intermittent 

Resources; Assessing the State of Wind Energy in 

Wholesale Electricity Markets, Notice of Proposed 

Rulemaking, 70 FR 21349 (Apr. 26, 2005), FERC 

Stats. & Regs. ¶ 32,581 at P 9 (2005) (Imbalance 

Provisions Proceeding). 

386The Commission defined incremental cost as 

‘‘the transmission provider’s actual average hourly 

cost of the last 10 MW dispatched to supply the 

transmission provider’s native load, based on the 

replacement cost of fuel, unit heat rates, start-up 

costs, incremental operation and maintenance costs, 

and purchased and interchange power costs and 

taxes.’’ Id. at P 9 n.17 (citing Consumers, 87 FERC 

¶ 61,170 at 61,179 (1999)). 

387Under existing Commission policy, a 

transmission provider may only charge a 

transmission customer for the penalty percent adder 

to the incremental cost for either hourly generator 

imbalances or hourly energy imbalances for the 

same imbalance. For example, if a transmission 

customer has a 100 MWh point-to-point schedule 

in a control area, but produces 105 MWh and 

consumes 105 MWh, the transmission provider may 

charge the transmission customer 110% of its 

incremental cost for the 5 MWh of energy 

imbalance, but then must pay the transmission 

customer its incremental cost for the 5 MWh 

generator imbalance. 

388See Duke Energy Corp., Docket No. ER05–855–

000 (Dec. 20, 2005) (unpublished letter order) 

(accepting Duke Electric Transmission’s Large 

Generator Interconnection Agreement with Power 

Ventures Group, LLC (Duke Delegated Letter 

Order)). 

389See Entergy Services, Inc., 90 FERC ¶ 61,272 

(2000) (concerning various generator imbalance 

agreements). 

390 See Duke Delegated Letter Order. 

391E.g., Ameren, Northwest IOUs, Progress 

Energy, Suez Energy NA, Public Power Council, 

Sacramento, South Carolina E&G, Pinnacle, 

Allegheny, TDU Systems, Constellation, Imperial, 

and Morgan Stanley. 

it returned the energy in kind at another 

time, would discourage good generator 

operating practices.381 The Commission 

stated that a generator’s interconnection 

agreement with its transmission 

provider or control area operator should 

specify the requirements for the 

generator to meet its schedule and any 

consequence for persistent failure to 

meet its schedule.382

632. The Commission subsequently 

accepted in a number of cases 

modifications to a transmission 

provider’s OATT to include generator 

imbalance provisions.383 Moreover, in 

Order No. 2003–B, the Commission 

permitted the transmission provider to 

include a provision for generator 

balancing service arrangements in 

individual interconnection 

agreements.384 Further, in a NOPR 

concerning generator imbalance 

provisions for intermittent resources, 

the Commission proposed to establish a 

standardized schedule under the pro 

forma OATT to address generator 

imbalances created by intermittent 

resources and to clarify the application 

of the current energy imbalance 

provision of the pro forma OATT.385 In 

particular, the Commission proposed 

that generator imbalance provisions for 

intermittent resources would reflect a 

deviation band of +/¥10 percent (with 

a minimum of 2 MW) and allow net 

hourly intermittent generator 

imbalances within the deviation band to 

be settled at the system incremental cost 

at the time of the imbalance.386 The 

Commission also reiterated its policy 

that a transmission provider may only 

charge the transmission customer for 

either hourly generator imbalances or 

hourly energy imbalances for the same 

imbalance, but not both.387

633. A variety of different deviation 

bands and pricing methods are on file 

for generator imbalances. Rates for 

generator imbalance underdeliveries 

range from the greater of $100/MWh or 

110 percent of system incremental cost 

to the greater of $150/MWh or 200 

percent of the incremental cost.388

Generator imbalance rates for 

overdeliveries range from 90 percent 389

of system decremental cost to 50 

percent 390 of the decremental cost. 

a. Tiered Approach to Imbalance 

Penalties in the OATT 

NOPR Proposal 

634. In the NOPR, the Commission 

noted that the existing energy imbalance 

charges described in Order No. 2003 are 

the subject of significant concern and 

confusion in the industry. The 

Commission expressed concern about 

the variety of different methodologies 

used for determining imbalance charges 

and whether the level of the charges 

provides the proper incentive to keep 

schedules accurate without being 

excessive. The Commission therefore 

proposed to modify the current pro 

forma OATT Schedule 4 treatment of 

energy imbalances and to adopt a 

separate pro forma OATT schedule for 

the treatment of generator imbalances. 

635. The Commission proposed to 

create new energy and generator 

imbalance schedules based on the 

following three principles: (1) The 

charges must be based on incremental 

cost or some multiple thereof; (2) the 

charges must provide an incentive for 

accurate scheduling, such as by 

increasing the percentage of the adder 

above (and below) incremental cost as 

the deviations become larger; and (3) the 

provisions must account for the special 

circumstances presented by intermittent 

generators and their limited ability to 

precisely forecast or control generation 

levels, such as waiving the more 

punitive adders associated with higher 

deviations. 

636. The Commission noted that 

Bonneville has adopted an energy 

imbalance pricing approach based on a 

three-tiered deviation band that appears 

workable for both energy imbalance 

service and generation imbalance 

service. Under this approach, 

imbalances of less than or equal to 1.5 

percent of the scheduled energy (or two 

megawatts, whichever is larger) would 

be netted on a monthly basis and settled 

financially at 100 percent of incremental 

or decremental cost at the end of each 

month. Imbalances between 1.5 and 7.5 

percent of the scheduled amounts (or 

two to ten megawatts, whichever is 

larger) would be settled financially at 90 

percent of the transmission provider’s 

system decremental cost for 

overscheduling imbalances that require 

the transmission provider to decrease 

generation or 110 percent of the 

incremental cost for underscheduling 

imbalances that require increased 

generation in the control area. 

Imbalances greater than 7.5 percent of 

the scheduled amounts (or 10 

megawatts, whichever is larger) would 

be settled at 75 percent of the system 

decremental cost for overscheduling 

imbalances or 125 percent of the 

incremental cost for underscheduling 

imbalances. Intermittent resources are 

exempt from the third-tier deviation 

band and pay the second-tier deviation 

band charges for all deviations greater 

than the larger of 1.5 percent or two 

megawatts. 

637. The Commission sought 

comment regarding whether this tiered 

approach should be adopted for 

inclusion in the pro forma OATT for 

energy and generator imbalances. The 

Commission specifically asked whether 

this approach provides sufficient 

incentives to ensure that transmission 

systems can be operated in a reliable 

manner and ensure that customers are 

treated in a just and reasonable manner. 

Comments 

638. A number of entities generally 

support a tiered approach to imbalance 

penalties that progressively increases 

the penalties for imbalances, as 

implemented by Bonneville.391 These 


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commenters generally state that a 

graduated bandwidth approach 

recognizes the link between escalating 

deviations and potential reliability 

impacts on the system. Other entities, 

however, take issue with aspects of the 

Commission’s proposal or propose a 

different approach to resolving 

imbalances. For example, Entegra 

submits that the Commission should 

require transmission providers to 

establish, or permit market participants 

to establish, markets or pools for the 

netting and settlement of imbalances. 

Steel Manufacturers Association argues 

for the Commission to require real-time 

balancing markets. 

639. Among those supporting the 

Commission’s proposal, Ameren asserts 

that the tiered approach properly allows 

for higher penalties for imbalances that 

have a greater impact on the system and 

thus have a greater potential to affect 

reliability. NorthWestern is not opposed 

to the generation imbalance provisions 

applying to all generators, arguing that 

imbalance charges must be based upon 

incremental cost and must provide an 

incentive for accurate scheduling. 

Morgan Stanley contends that basing the 

imbalance charge on incremental cost 

should be a bedrock principle for 

developing methods to financially settle 

imbalances. 

640. Progress Energy, Sacramento, 

and Entergy encourage the Commission 

to allow each transmission provider to 

have the flexibility to craft penalty 

provisions that provide the right 

incentives to encourage their 

transmission customers to act 

responsibly. Grant similarly contends 

that the transmission provider must be 

able to decide what to charge for 

imbalance services and must consider 

the incentives for resource development 

and the potential for cross-subsidies 

paid by other customers associated with 

such pricing. Grant argues that 

transmission providers should have an 

ability to ‘‘opt out’’ if they can 

demonstrate an inability to provide the 

service without creating an undue 

burden on other ratepayers. 

641. Constellation, while supporting 

the Commission’s proposal, asks that 

transmission providers be required to 

utilize a security-constrained economic 

dispatch to procure and settle 

imbalances at least cost, which would 

ensure that least cost is determined on 

the most efficient basis. Constellation 

contends that imbalance charges should 

be based on the transmission provider’s 

actual cost of meeting a positive 

imbalance or liquidating a negative 

imbalance, which costs can include 

required ancillary services and 

redispatch costs. Morgan Stanley states 

that facing an imbalance cost measured 

by full replacement value of redispatch 

measured under LMP would be an 

appropriate incentive. Morgan Stanley 

contends that the pro forma OATT 

should specify using opportunity cost 

principles to charge for imbalance 

solutions in those areas without LMP 

and come as close to mimicking the 

result under LMP as possible. In reply 

comments, Mark Lively suggests the 

Commission make the price for 

imbalances a function of the size of Area 

Control Error. Public Power Council 

recommends that transmission 

providers not assess penalties against 

loads or resources when their deviations 

from the schedule help the system in a 

given delivery hour. TDU Systems argue 

that inadvertent scheduling errors that 

do not threaten system integrity or 

reliability should not be penalized 

through charges for imbalances that 

exceed incremental cost in the upper 

tiers of imbalance bandwidths. 

642. Although FirstEnergy states that 

the Bonneville approach for generator 

imbalances is appropriate, it argues that 

the current pro forma OATT 

methodology for calculating and 

assessing energy imbalances should be 

retained. FirstEnergy argues that it is 

more appropriate and fair to apply a 

graduated penalty structure to 

generation imbalances since greater 

deviations usually occur from 

generation. Ameren, however, believes 

that generators are generally better able 

to control their imbalances than 

transmission customers who take energy 

off of the system and that the use of a 

narrower deviation band may be 

appropriate for generator imbalances. 

Nonetheless, Ameren states that it does 

not oppose the Commission’s proposal 

to use the same deviation bandwidths 

for both energy imbalances and 

generator imbalances. 

643. Ameren contends that 

developing standardized provisions for 

generator imbalances in the OATT 

would eliminate the plethora of 

penalties that now exist. Ameren asserts 

that moving to a tariff approach would 

increase transparency and would help 

address the situation where such 

provisions may appear either in the 

relevant OATT or in specific 

interconnection agreements (at least for 

interconnection agreements entered into 

as of the date of the revised tariff 

provisions). Progress Energy and South 

Carolina E&G support separate tariff (or 

Generator Interconnection Agreement) 

provisions for these services, suggesting 

that generator and energy imbalance 

provisions could be tailored for 

generators and LSEs. NorthWestern 

states that it has long been an advocate 

of the inclusion of a generation 

imbalance OATT mechanism. TDU 

Systems contend that the Commission 

should require that the specific 

bandwidths and the basis for the 

charges be spelled out in detail in the 

revisions to the pro forma OATT and in 

each transmission provider’s tariff. 

Allegheny argues that changing Energy 

Imbalance Service from Schedule 4 to 

Schedule 4a, adding a new Schedule 4b 

for Generator Imbalance Service, and 

eliminating proposed Schedule 9 would 

call attention to the fact that a 

transmission provider may only charge 

a transmission customer either an 

hourly generator imbalance charge or an 

hourly energy imbalance charge, but not 

both for the same imbalance. 

644. Other entities contend that the 

Commission’s imbalance proposal will 

not do enough to protect reliability and 

prevent entities from deviating from 

their schedules. Entergy states that the 

Commission should recognize that a 

system with significant hydro resources, 

such as the Bonneville system, faces 

different challenges in matching 

generation and load than a system with 

predominantly thermal generation. 

Unlike the fast ramping capability of 

hydro units, Entergy asserts that thermal 

units have a more limited ability to 

adjust and compensate for imbalances. 

Entergy adds that the Bonneville model 

may not provide sufficient incentives in 

those areas with large amounts of 

independent generation. In reply 

comments, some APPA members noted 

that wind variability may pose 

significant operational concerns that 

could increase regulating reserve 

requirements, particularly on smaller 

transmission systems. 

645. Steel Manufacturers Association 

asks the Commission to delete any 

further reference to charges based on 

some multiple of incremental costs, 

which applies to scheduling incentives, 

not cost recovery. It believes that 

charges based on multiples of 

incremental costs are not necessary and 

do not produce rates that are just and 

reasonable. Steel Manufacturers 

Association asserts that balancing 

mechanisms based on real time marketclearing prices provide full 

compensation and adequate scheduling 

incentives in the organized markets and 

there is no reason to apply a deadband/ 

penalty mechanism for individual 

OATT providers unless there is a 

demonstrated need, i.e., a showing that 

excessive gaming by LSEs or generators 

has been a problem. 

646. Steel Manufacturers Association 

also contends that the current imbalance 

mechanism is a losing proposition for 

loads that cannot control energy 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12347 

392E.g., NorthWestern, Fertilizer Institute, and 

Geothermal Producers. 

consumption to match an hourly 

schedule of energy deliveries, with 

transmission providers receiving 

windfall revenues. It argues that the 

mechanism is unfair to smaller 

transmission systems that are not 

control areas (and therefore may not 

settle all of their imbalances through 

return-in-kind energy) and certain retail 

customers that take unbundled retail 

transmission service. Steel 

Manufacturers Association asks the 

Commission to institute a larger 

bandwidth of, at minimum, 10 percent 

for small wholesale customers and 

discrete retail loads. It contends that 

large utilities and wholesale 

transmission customers that acquire 

power for many discretely operated 

loads with varying load stages and load 

factors and averaging those loads creates 

an overall predictability to load curves 

that permits the practical use of a 1.5 

percent bandwidth for large utilities and 

wholesale customers. 

647. Utah Municipals assert that the 

Commission is wrong to believe that 

imbalances tend to result from 

carelessness or intentional conduct 

rather than unavoidable uncertainties 

and error. Utah Municipals contend 

that, while technology that permits 

perfectly accurate scheduling (i.e., 

namely the AGC equipment used by 

control area operators) is theoretically 

available, it is prohibitively expensive 

for many transmission customers and 

unavailable to those who do not own 

generation. Utah Municipals argue that 

financial incentives for accurate 

scheduling do not alter scheduling 

behavior or actual imbalances, but only 

result in a potential windfall for the 

transmission provider and a potentially 

significant competitive advantage for 

the transmission provider’s market 

function, which (because of the AGC 

equipment that all transmission 

customers pay for through rates) will 

not be subject to the charges. Utah 

Municipals suggest that the Commission 

limit the imbalance charges for 

unintentional deviations by applying 

the third deviation band only to 

intentional imbalances. 

648. Imperial argues that the 

Bonneville approach would not provide 

appropriate incentives for small 

geothermal generating units on its 

system to control their scheduled 

output, especially if imbalances are 

recorded on an hourly basis rather than 

on a cumulative basis over the course of 

a month. Under the Bonneville 

approach, Imperial asserts that it would 

have to pay its generators 100 percent of 

its incremental cost for overgeneration 

because such imbalances are usually 

less than 2 MW in any given hour. It 

states that using a 100 percent credit for 

net overgeneration would result in 

crediting the generator more than 

$28,500. 

649. WECC states that it is very 

important to differentiate between the 

kind of behavior that the Commission is 

worried about and appropriate practices 

that support system reliability. WECC is 

concerned that inflexible generator 

imbalance provisions in the pro forma 

OATT may create incentives for 

generators in the West to restrict 

governor action on their generators in 

ways that degrade system reliability. 

WECC notes that the number of rotating 

machines connected to the grid in the 

Eastern Interconnection is much greater 

than in the Western Interconnection, 

which impacts the ability of generators 

to respond to maintain frequency when 

a system’s load-resource balance 

changes. WECC explains that a sudden 

change in load-resource balance of a 

particular magnitude (for example, the 

loss of a 1,000 MW generating plant) 

will require a proportionately greater 

response from each generating unit in 

the West as compared to the Eastern 

Interconnection. WECC contends that in 

the West a significant frequency decline 

could cause responding generators to 

exceed a 1.5 percent deviation threshold 

applied under current pro forma Tariff 

imbalance schedules. 

650. If the manner of implementing 

generator imbalance charges in the West 

does not consider the need for 

generators to respond to frequency 

deviations, WECC worries that these 

charges could produce perverse 

incentives that will undermine 

reliability. WECC argues that generators 

that use set-point controllers to override 

governor action will be less likely to 

incur imbalance charges and penalties, 

while those with properly operating 

governors may be punished for 

deviating from scheduled output to 

respond to system reliability needs. 

WECC believes that this has in fact been 

happening in the West and is one of the 

reasons that frequency response in the 

Western Interconnection has 

deteriorated in recent years. WECC 

urges the Commission to consider how 

generators can be given appropriate 

incentives to meet their obligations to 

supply energy to load but also to 

support system reliability by effectively 

responding to frequency deviations. 

WECC explains that the Commission 

could adopt a policy that set-point 

controllers should not be allowed to 

override governor response. WECC 

suggests that deviations from scheduled 

generator output needed to correct 

frequency decay could be excused from 

imbalance penalties under the pro 

forma OATT. 

651. Indianapolis Power contends on 

reply that variation should be allowed 

to account for the individual facts and 

circumstances associated with a specific 

region as well as specific types of 

intermittent resources. A number of 

entities agree with providing flexibility 

to intermittent generators, but suggest 

different ways of doing so.392 Fertilizer 

Institute agrees that intermittent 

resources should be exempt from any 

penalties beyond the 90 percent/110 

percent ‘‘second tier.’’ However, 

Fertilizer Institute also believes that 

intermittent resources should receive 

greater tolerance before they run into 

the 90 percent/110 percent penalty level 

in the first place. Fertilizer Institute 

urges the Commission to relax the firsttier tolerance band from 2MW to 20MW 

(or 40 percent of nameplate capacity, 

whichever is greater) for intermittent 

generators only. It asserts that this 

action is consistent with the 

Commission’s recognition that 

intermittent generators can undergo 

sudden changes of conditions for which 

they cannot fairly be held responsible. 

Fertilizer Institute argues that a broader 

first-tier tolerance band for these 

generators will present no threat to the 

transmission grid, because intermittent 

generation facilities are limited both in 

size and in number. 

652. Geothermal Producers supports a 

first-tier deviation band of +/¥5 percent 

for intermittent resources, rather than 

the 1.5 percent threshold proposed by 

Bonneville. Geothermal Producers 

believes a 5 percent band is appropriate 

for intermittent resources, since a five 

percent band more accurately 

recognizes that intermittent resources 

are less capable of controlling 

deviations from schedules than are 

conventional resources. For over- or 

under-deliveries in excess of five 

percent, Geothermal Producers contends 

that intermittent resources should be 

charged no more than the control area’s 

cost of supplying energy to correct the 

imbalance. Geothermal Producers also 

supports Bonneville’s position that 

intermittent resources should be exempt 

from the third-tier deviation band and 

instead should pay the second-tier 

deviation band charges for all deviations 

greater than the second-tier deviation 

band. 

653. Other commenters, however, do 

not support providing exceptions for 


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12348 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

393E.g., Morgan Stanley, Northwest IOUs, Steel 

Manufacturers Association, and TDU Systems. 394E.g., Fertilizer Institute, Entegra, and TAPS. 

intermittent resources.393 If society 

decides to provide incentives for 

intermittent resources, Morgan Stanley 

states that this is better done in a direct 

fashion, such as a certification program 

akin to resource adequacy rules that 

require LSEs to source a proportion of 

supply from such resources. Morgan 

Stanley asserts that this would motivate 

developers to mitigate imbalance costs 

through other market or technical means 

to the full extent of the economic signal 

imbedded in the imbalance price and 

thereby optimize the design and 

operation of such resources. 

MidAmerican argues on reply that 

special treatment of intermittent 

resources and loads has the effect of 

penalizing those resources and loads 

that have made investments to manage 

scheduling and enhance reliability. TDU 

Systems believe that the NOPR’s third 

principle, which requires transmission 

providers to accord special treatment to 

intermittent generators, is contrary to 

the principle of comparability. 

654. Northwest IOUs argue that the 

transmission provider should have the 

option to elect whether to exempt 

intermittent resources from the thirdtier deviation band and instead charge, 

in a not unduly discriminatory or 

preferential manner, the second-tier 

deviation band charge for all deviations 

greater than the larger of 1.5 percent or 

2 megawatts. 

655. Several commenters suggested 

that the Commission include a 

definition of intermittent resource in the 

final rule. Fertilizer Institute and South 

Carolina E&G contend that it is essential 

for the Commission to provide a clear 

definition of ‘‘intermittent generation’’

or ‘‘intermittent resource’’ to avoid 

disputes. Fertilizer Institute argues that 

the question of whether a given 

generator is ‘‘intermittent’’—and thereby 

entitled to the special provisions—is 

likely to become a source of contention. 

Fertilizer Institute suggests that an 

intermittent resource be defined as ‘‘an 

electric generator that (1) Cannot store 

its fuel sources and (2) has limited 

capability to be dispatched and to 

respond to changes in system demand 

and transmission security constraints.’’

EEI, however, suggests that the 

definition apply only to weather-driven 

units. Fertilizer Institute argues on reply 

that restricting the definition in this way 

would be unduly discriminatory. 

Fertilizer Institute argues that the 

definition should include the most 

common forms of intermittent 

generation—wind and solar power—as 

well as the less common but equally 

valuable forms, such as generation with 

ocean energy or ‘‘waste heat’’ from an 

industrial process. Fertilizer Institute 

asserts that the Commission should not 

broaden the definition of intermittent 

resource to encompass generators who 

are not truly ‘‘intermittent’’ and should 

not narrow the definition to exclude 

some intermittent generators in favor of 

others. Fertilizer Institute contends on 

reply that a generator should not have 

to be ‘‘weather-driven’’ to qualify as 

‘‘intermittent.’’ Geothermal Producers 

supports the inclusion of geothermal 

energy as an intermittent resource. 

Geothermal Resources contends that 

geothermal resources satisfy both the 

Commission’s proposed definition and 

the EEI proposal. 

656. Ameren and Entergy ask the 

Commission to clarify that it does not 

intend to amend any existing 

interconnection agreements to require 

the use of any pro forma imbalance 

penalties. Entergy believes that the 

present form of its Generation 

Interconnection Agreement is absolutely 

critical to managing imbalances on its 

system and maintaining reliability. 

Entergy states that it has developed 

specialized software to monitor and 

manage generator imbalances and 

employs six system operators (one per 

shift) to monitor and manage generator 

imbalances. 

657. Although Entergy supports the 

‘‘grandfathering’’ of existing generator 

imbalance arrangements, it does not 

believe that it would be appropriate to 

require the prospective use of a different 

methodology while simultaneously 

maintaining the grandfathered 

arrangements. Entergy contends that 

administering two different generator 

imbalance arrangements would not be 

consistent with the comparability 

principles of Order No. 888 and would 

be difficult and costly from an 

operational perspective. 

658. Several commenters 394 argue on 

reply that it would be inappropriate for 

the Commission to grandfather existing 

imbalance provisions. In its reply 

comments, Entegra argues that prior 

arrangements should remain in place 

only if a transmission provider can 

demonstrate that its existing imbalance 

arrangements are consistent with or 

superior to the provisions of the pro 

forma OATT as modified by the Final 

Rule in this proceeding. 

659. EEI and Exelon contend that the 

transmission provider may not be able 

to charge a generator under its OATT if 

the generator is not the transmission 

customer and, therefore, generators 

should be able to include standardized 

imbalance terms in agreements with 

eligible customers prior to providing 

service. Exelon suggests that the 

Commission both adopt in the pro 

forma OATT a standard imbalance 

penalty structure and direct 

transmission providers to include the 

same terms and conditions in their 

interconnection agreements with 

generators. TAPS suggests on reply that 

each generator could simply be required 

to sign a service agreement that requires 

it to comply with the generator 

imbalance provisions of the 

transmission provider’s OATT. Unless 

the pro forma OATT governs both 

generator and load imbalances, TAPS 

argues that it would be impossible to 

implement and enforce the 

Commission’s prohibition against 

charging both energy and generator 

imbalances for a single transaction. 

660. ICNU argues on reply that the 

Commission should adopt less 

restrictive imbalance charges for retail 

access customers or, at a minimum, 

continue to recognize that the standard 

energy imbalance charge needs to be 

modified to accommodate direct access 

customers. ICNU asks the Commission 

to modify its proposed imbalance 

provision to reflect the unique 

characteristics of direct access 

customers by adopting wider imbalance 

bandwidths and/or waiving the more 

punitive adders associated with higher 

deviations. 

661. Several entities assert that the 

proposed imbalance reform should not 

apply to RTOs. Exelon requests that the 

Commission explicitly state that these 

rules do not apply in regions that have 

organized markets, such as PJM, that 

obviate the need for imbalance 

penalties. They contend that within 

organized markets, an imbalance 

penalty rule is not necessary, as the 

independent transmission operators 

have effectively addressed the concerns 

that the proposed imbalance schedules 

are intended to address. Indicated New 

York Transmission Owners contend that 

the Commission should grant the 

NYISO a regional variation from the 

revised pro forma OATT with respect to 

imbalance charges. It contends that the 

existing mechanisms in ISO/RTO 

markets with LMP are consistent with 

the Commission’s objectives in its 

NOPR and that the Commission should 

permit a regional variation to the 

NYISO. SPP states that the Commission 

should state that it does not intend to 

affect its effort to implement a real-time 

energy imbalance market by any final 

rule. SPP further contends that the 

Commission should clarify that its 

energy imbalance changes do not apply 

to ISOs and RTOs with organized 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12349 

395See Docket No. RM05–10–000. We note that 

this definition was proposed by the Commission in 

the NOPR on Imbalance Provisions for Intermittent 

Resources. See Imbalance Provisions for 

Intermittent Resources; Assessing the State of Wind 

Energy in Wholesale Electricity Markets, Notice of 

Proposed Rulemaking, 70 FR 21349 (Apr. 26, 2005), 

FERC Stats. & Regs. ¶ 32,581 (2005). 

markets providing for real-time energy 

imbalance markets. SPP believes that 

the Commission should view the 

existence of a spot energy price in 

organized markets as superior to 

penalties based on incremental costs or 

some multiple thereof. 

662. Entegra suggests that, since many 

RTOs have (or are developing) separate 

markets for commitment costs, it may 

not be necessary to incorporate such 

costs into imbalance prices in certain 

RTO markets. Organizations of MISO 

and PJM States contend that this 

proposed change to Schedule 4 is not 

applicable in the RTO context and argue 

that, to the extent that the Commission’s 

suggestions regarding the special 

circumstances presented by intermittent 

generators are applicable to RTOs, those 

issues are best addressed in a context 

other than the instant rulemaking 

proceeding. 

Commission Determination 

663. In order to increase consistency 

among transmission providers in the 

application of imbalance charges, and to 

ensure that the level of the charges 

provides appropriate incentives to keep 

schedules accurate without being 

excessive, the Commission adopts in the 

pro forma OATT imbalance provisions 

similar to those implemented by 

Bonneville. We agree with commenters 

that a graduated bandwidth approach 

recognizes the link between escalating 

deviations and potential reliability 

impacts on the system. Furthermore, we 

conclude that these provisions adhere to 

the three principles discussed in the 

NOPR, which we also adopt here: (1) 

The charges must be based on 

incremental cost or some multiple 

thereof; (2) the charges must provide an 

incentive for accurate scheduling, such 

as by increasing the percentage of the 

adder above (and below) incremental 

cost as the deviations become larger; 

and (3) the provisions must account for 

the special circumstances presented by 

intermittent generators and their limited 

ability to precisely forecast or control 

generation levels, such as waiving the 

more punitive adders associated with 

higher deviations. 

664. Specifically, imbalances of less 

than or equal to 1.5 percent of the 

scheduled energy (or two megawatts, 

whichever is larger) will be netted on a 

monthly basis and settled financially at 

100 percent of incremental or 

decremental cost at the end of each 

month. Imbalances between 1.5 and 7.5 

percent of the scheduled amounts (or 

two to ten megawatts, whichever is 

larger) will be settled financially at 90 

percent of the transmission provider’s 

system decremental cost for 

overscheduling imbalances that require 

the transmission provider to decrease 

generation or 110 percent of the 

incremental cost for underscheduling 

imbalances that require increased 

generation in the control area. 

Imbalances greater than 7.5 percent of 

the scheduled amounts (or 10 

megawatts, whichever is larger) will be 

settled at 75 percent of the system 

decremental cost for overscheduling 

imbalances or 125 percent of the 

incremental cost for underscheduling 

imbalances. 

665. The Commission adopts 

Bonneville’s tariff provisions that 

provide that intermittent resources are 

exempt from the third-tier deviation 

band and would pay the second-tier 

deviation band charges for all deviations 

greater than the larger of 1.5 percent or 

two megawatts. We believe this is 

consistent with the fact that intermittent 

generators cannot always accurately 

follow their schedules and that high 

penalties will not lessen the incentive to 

deviate from their schedules. 

666. Several commenters argue that 

the Commission should adopt a 

standard definition of intermittent 

resource. In order to clarify application 

of imbalance charges, we define an 

intermittent resource for this limited 

purpose as ‘‘an electric generator that is 

not dispatchable and cannot store its 

fuel source and therefore cannot 

respond to changes in system demand 

or respond to transmission security 

constraints.’’ 395 We conclude that this 

definition of intermittent resource 

properly limits the exemption from 

imbalance charges, without excluding 

certain classes of intermittent generators 

for which the exemption is appropriate 

(e.g., non-weather driven intermittent 

resources). 

667. The Commission believes that 

adopting a tiered approach for both 

energy and generation imbalances will 

best balance the needs of transmission 

providers to operate their transmission 

systems in a reliable manner with the 

needs of transmission customers to have 

reasonable access to those systems at 

just and reasonable rates. Furthermore, 

we conclude that the partial exemption 

from imbalance charges for intermittent 

resources appropriately reflects the 

special circumstances faced by such 

resources and, consequently, is not 

unduly discriminatory. Moreover, 

formalizing generator imbalance 

provisions in the pro forma OATT will 

standardize the future treatment of such 

imbalances from the wide variety of 

generator imbalance provisions that 

exist today in various generator 

interconnection agreements. 

Standardizing generator imbalances 

should lessen the potential for undue 

discrimination, increase transparency 

and reduce confusion in the industry 

that results from the current plethora of 

different approaches. 

668. Several commenters debate 

whether the imbalance provisions 

adopted here should be applied to 

energy imbalances, generation 

imbalances, or both. The Commission 

concludes that subjecting both energy 

and generation imbalances to the same 

charges is appropriate. Energy and 

generation imbalances have the same 

net effects on the transmission system in 

requiring other generation to be ramped 

up or down to make up for the 

imbalance. As such, the Commission 

will modify the current pro forma 

OATT Schedule 4 treatment of energy 

imbalances and adopt a new separate 

pro forma OATT Schedule 9 for the 

treatment of generator imbalances, each 

based on the tiered structure described 

above. To the extent a transmission 

provider wishes to deviate from these 

revised pro forma provisions, it may 

demonstrate in an FPA section 205 

proceeding that the proposed changes 

are consistent with or superior to the 

pro forma OATT as modified by this 

Final Rule. However, we note that 

proposed alternative provisions must 

comply with the three imbalance charge 

principles addressed in the NOPR and 

adopted in this Final Rule and be 

consistent with or superior to the 

specific imbalance charges set forth in 

the pro forma OATT (and discussed 

above). 

669. Some commenters stated that the 

Commission should require 

transmission providers to establish, or 

permit market participants to establish, 

markets or pools for the netting and 

settlement of imbalances. As explained 

previously, the purpose of this rule is to 

strengthen the pro forma OATT to 

remedy undue discrimination and not to 

impose any particular market structure. 

If transmission providers offer to modify 

their OATTs to allow such pools, we 

will consider such proposals. But, 

imposing such requirements goes 

beyond the scope of this proceeding. 

The Commission therefore declines, for 

all these reasons, to impose the 

structural reforms requested by some 

commenters. 

670. The Commission instead adopts 

the three-tiered approach in the pro 


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12350 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

396See 2006 Transmission and Ancillary Service 

Rate Schedules, approved in United States Dep’t of 

Energy—Bonneville Power Administration, 112 

FERC ¶ 62,258 (2005). The Bonneville tariff 

provides that ‘‘For any hour(s) that an imbalance is 

determined by [Bonneville] to be an Intentional 

Deviation: (1) No credit is given when energy taken 

is less than the scheduled energy, (2) When energy 

taken exceeds the scheduled energy, the charge is 

the greater of: (i) 125% of [Bonneville’s] highest 

incremental cost that occurs during that day, or (ii) 

100 mills per kilowatthour.’’ An ‘‘Intentional 

Deviation’’ is defined as ‘‘a deviation that is 

persistent during multiple consecutive hours or at 

specific times of the day,’’ a ‘‘pattern of underdelivery or over-use of energy,’’ or ‘‘persistent overgeneration or under-use during Light Load Hours, 

particularly when the customer does not respond by 

adjusting schedules for future days to correct these 

patterns.’’ Id. at 46. 

397E.g., Imperial District Irrigation, Progress 

Energy and Ameren. 

398The Commission noted that ‘‘capacity 

commitment’’ is generally defined as the generating 

capacity committed by a utility to provide 

capability for another utility to attain its reserve 

level. See, e.g., Central & South West Services, Inc., 

48 FERC 61,197 at 61,731 n.9 (1989). 

399The Commission proposed defining 

incremental cost, based on its decision in 

Consumers, as the transmission provider’s actual 

average hourly cost of the last 10 MW dispatched 

to supply the transmission provider’s native load, 

based on the replacement cost of fuel, unit heat 

rates, start-up costs, incremental operation and 

forma OATT. As with other reforms 

adopted in this Final Rule, all 

transmission providers must submit 

compliance filings containing these pro 

forma tariff provisions. Transmission 

providers with previously-approved 

tariff provisions governing imbalances 

that no longer conform to the pro forma 

OATT, as revised in this Final Rule, 

may seek renewed approval of those 

tariff deviations in accordance with the 

procedures described in section IV.C 

above, demonstrating that the 

alternative imbalance charge structures 

are consistent with or superior to the 

reformed pro forma OATT. With respect 

to the concerns raised by ISOs and 

RTOs, we agree that LMP-based markets 

can provide an efficient and 

nondiscriminatory means of settling 

imbalances and, as indicated in the 

NOPR, we are not proposing to redesign 

ISO/RTO markets in this rulemaking. 

Nevertheless, ISOs and RTOs must 

follow the procedures described in the 

Applicability section for seeking 

approval of deviations that are 

consistent with or superior to the pro 

forma OATT. 

671. We do not, however, abrogate 

existing generator imbalance agreements 

between transmission providers and 

their customers. These agreements have 

been negotiated between willing parties, 

and the Commission will not re-open 

them generically in this proceeding. To 

the extent a particular party desires to 

amend an existing generator imbalance 

agreement in light of the reforms we 

adopt in this Final Rule, that party may 

exercise whatever rights it may have 

under the agreement or FPA section 

206. 

672. With regard to WECC’s 

frequency-response concerns, we agree 

that a generator should be excused from 

imbalance penalties that occur due to 

directed reliability actions by generators 

to correct frequency. It would not be 

appropriate to assess imbalance charges 

on generator deviations that are 

associated with supporting system 

reliability by responding to frequency 

deviations as directed by the 

transmission provider or general 

reliability requirements. As such, if a 

response from a generator (particularly 

in the West) is required to prevent 

frequency decay and the corresponding 

deviations from the generator’s schedule 

would cause additional imbalance 

penalties, the transmission provider 

should exempt the generator from those 

penalty charges. 

b. Intentional Deviations 

NOPR Proposal 

673. In the NOPR, the Commission 

noted that the Bonneville imbalance 

provision allows for greater charges 

when a customer has an ‘‘intentional 

deviation.’’ 396 The Commission sought 

comment on whether the pro forma 

OATT imbalance provision should 

provide for similar penalties for 

behavior that represents deliberate 

reliance on the transmission provider’s 

generation resources, as opposed to 

scheduling errors, with such penalties 

being subject to prior notice and 

approval by the Commission and based 

on the facts and circumstances of the 

individual transmission provider. 

Comments 

674. Several entities contend that 

higher imbalance charges and penalties 

for deliberately leaning on the grid can 

be appropriate.397 Imperial supports an 

imbalance provision that allows for 

greater charges for persistent or 

patterned deviations. Pinnacle agrees 

that deliberate reliance on the 

transmission provider’s generation 

resources is inappropriate and could 

adversely affect the reliability of the 

transmission system, but they are 

unsure if such an intentional deviation 

could be proven. Imperial also expresses 

concern that the burden to prove the 

intent of the generator will fall on 

transmission providers and that, in 

reality, transmission providers may face 

an uphill battle to prove a generator’s 

deviation was intended. South Carolina 

E&G and Imperial request that the 

Commission provide a specific process 

for imposing such penalties, including 

what procedures should be followed if 

a transmission provider seeks to have 

the Commission impose such penalties. 

675. Several entities oppose penalties 

for intentional deviations or suggest 

modifications. Constellation supports an 

elimination of the separate penalty 

structure for customers deliberately 

leaning on the system. Constellation and 

Grant believe that a graduated 

percentage adder/discount will provide 

the right incentives and disincentives 

without the need for an intentional 

deviation provision. If deviation costs 

are properly calculated, Morgan Stanley 

contends that requiring those who 

deviate to pay the full marginal cost of 

that deviation would result in fair 

allocation of cost responsibility and 

sufficient stability of system operations 

as a result of both cost and risk 

avoidance by participants. TDU Systems 

argue that the Commission should 

eliminate the 100 mill per kWh floor for 

penalties for intentional deviations. 

Commission Determination 

676. The Commission recognizes the 

need to provide transmission customers 

with the appropriate incentives not to 

intentionally dump power on the 

system or lean on other generation. We 

do not believe, however, that separate 

penalties for intentional deviations need 

to be generically imposed in the pro 

forma OATT. The tiered imbalance 

penalties adopted in this Final Rule 

generally provide a sufficient incentive 

not to engage in such behavior. 

Proposals to assess additional penalties 

for intentional deviations will continue 

to be considered on a case-by-case basis, 

subject to a showing that they are 

necessary under the circumstances. We 

note that any such tariff provisions must 

include clearly defined processes for 

identifying intentional deviations and 

the associated penalties. 

c. Calculation of Incremental Cost 

NOPR Proposal 

677. With respect to the pricing of 

energy and generation imbalances, the 

Commission stated in the NOPR its 

belief that charges based on incremental 

costs or multiples of incremental costs 

would provide the proper incentive to 

keep schedules accurate without being 

excessive. The Commission proposed 

that incremental cost be defined to 

include both energy and 

commitment 398 costs, to the extent 

additional commitments are needed.399


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maintenance costs, and purchased and interchange 

power costs and taxes. 

400E.g., Allegheny, Ameren, Indicated New York 

Transmission Owners, and FirstEnergy. 

The Commission sought comment on 

how such charges should be calculated, 

as well as how they would be applied 

to transmission customers. The 

Commission sought further comment as 

to how additional demand and energy 

costs, if incurred in responding to 

imbalances, such as redispatch, 

commitment, or additional regulation 

reserves, should be appropriately 

reflected in the calculation of imbalance 

charges and which customers should be 

charged for such costs. 

Comments 

678. Several entities argue that 

incremental pricing for both energy 

imbalances and generator imbalances 

should reflect the full incremental costs 

incurred by the transmission provider 

(e.g., such as redispatch costs, capacity 

commitment costs or additional 

regulation reserve costs) resulting from 

the imbalance.400 Allegheny questions 

whether the Consumer’s definition is 

appropriate because ‘‘the last 10 MW’’

requirement is independent of the time 

of the scheduling deviation. Allegheny 

contends that the definition should be 

modified such that it specifically 

addresses the incremental dispatch to 

supply the transmission provider’s load 

‘‘in the hour in which the imbalance 

occurs.’’

679. Entergy argues that imbalance 

pricing on an hourly basis does not 

capture all of the costs and reliability 

risk to the transmission provider of 

over- and under-deliveries. Entergy 

states that the real-time regulation 

burden imposed by IPPs is similar to the 

real-time regulation burden imposed by 

loads, and loads are charged for this cost 

through a transmission provider’s 

Schedule 3 Regulation and Frequency 

Response Service. Entergy asserts that 

the NOPR does not propose any 

recovery mechanism for the regulation 

burden imposed by IPPs, recognizing 

that Bonneville may not face significant 

generator regulation costs due to the 

rapid ramping rate and relatively low 

cost of hydroelectric resources. Entergy 

submits that its regional experience has 

demonstrated that generator regulation 

service is a necessity. Entergy states that 

its generator regulation service recovers 

charges for the generating capacity that 

Entergy must maintain on-line in order 

to respond to the moment-to-moment 

deviations between scheduled output 

and actual generation. Entergy explains 

that the charge compensates Entergy on 

a cost-basis for the generation capacity 

used by IPPs, while at the same time 

sending the appropriate economic signal 

that encourages generators to match 

their generation with their schedules. 

680. In its reply comments, EEI argues 

that a transmission provider should be 

entitled to recover the cost of additional 

reserves needed to meet the increased 

reliability requirements resulting from 

the provision of the imbalance energy if 

the transmission provider generates 

additional energy to compensate for a 

load that schedules less energy than it 

takes or a generator that produces less 

energy than it schedules. EEI further 

contends that transmission providers 

should be permitted to include in their 

calculation of imbalance charges any 

other costs associated with committing 

a unit that is not on-line such as 

minimum run times, losses, etc. 

681. Entergy opposes a single price for 

settling over-deliveries and underdeliveries. For transmission providers 

who choose to base energy and 

generator imbalance charges on 

incremental and decremental costs, 

Entergy requests that the Commission 

not adopt standardized definitions of 

incremental cost and decremental cost 

in the pro forma OATT. In its reply 

comments, Entergy further argues that a 

requirement that the transmission 

provider post incremental and 

decremental cost information is unfair 

and harmful to the market, placing the 

transmission provider at an unfair 

competitive disadvantage in the market. 

Duke on reply proposes that System 

Incremental Cost (SIC) be used to price 

both over-deliveries and underdeliveries. Duke defines SIC to mean the 

incremental expense, measured in 

dollars per megawatt hour, incurred by 

the utility to produce or procure the 

next megawatt hour (MWh) of energy, 

after serving all of the utility’s electric 

energy and/or capacity sales. Duke 

proposes that SIC shall include but not 

be limited to: The replacement cost of 

fuel; incremental operating and 

maintenance costs; emissions allowance 

replacement costs and other 

environmental compliance costs; the 

cost of starting and operating any 

generating units, (including costs 

incurred due to minimum runtimes or 

loading levels); purchase and 

interchange power costs; and all 

applicable taxes or assessments based 

on the revenues received or quantities 

sold. 

682. Allegheny states that the 

Commission should clarify that the 

definition of incremental cost is equally 

applicable to intermittent generator 

imbalance service as well as nonintermittent generator imbalance 

service. 

683. Pinnacle and Utah Municipals 

request that the Commission allow the 

use of alternative pricing 

methodologies, such as market proxy 

pricing methodology based on trading 

hubs in or adjacent to their respective 

control areas, where appropriate. Utah 

Municipals urge the Commission to 

make clear in the final rule that marketbased pricing may be acceptable in 

some circumstances and to amend 

Schedule 4 of the pro forma OATT to 

ensure that imbalance charges are 

designed not only to provide legitimate 

incentives for accurate scheduling, but 

also to avoid unjustified penalties 

(masquerading as ‘‘incentives’’), to 

minimize the discriminatory impact of 

such charges, and to avoid penalizing 

behavior or results that in fact help to 

keep the system as a whole in balance. 

684. TDU Systems believe the 

Commission should disallow recovery 

of demand charges or capacity 

commitment costs in any charges 

approved for imbalances. TAPS and 

TDU Systems argue that capacity 

required to follow load is already paid 

for by charges for regulation and 

reserves under Schedules 3, 5 and 6. 

TDU Systems also support that the 

Commission continue to apply its 

existing policy of imposing a heavy 

burden on transmission providers to 

justify such demand or capacity 

commitment charges in the context of a 

full base rate case, and of requiring 

transmission providers to develop 

alternative solutions for balancing 

schedules and loads. 

685. To the extent transmission 

providers are permitted to include 

commitment costs in negative 

imbalance charges, Entegra believes that 

additional monitoring would be needed, 

to include posting of hourly imbalance 

charges, even if with a lag of a day or 

so. Suez Energy NA contends that the 

Commission should require a 

transmission owner to support its 

incremental cost filing on the basis of 

Form No. 423 data and actual operations 

of the selected units, based on 

operational data as reported in utilities 

Continuous Emission Monitoring 

reports. 

686. EEI argues that since Schedule 3, 

5 and 6 charges recover the costs of 

capacity based on test year data, they 

would not recover the additional costs 

of reserves that transmission providers 

incur to compensate for their customers’

failures to match their schedules and 

their loads or generator output, and they 

also do not recover other commitment 

costs such as start-up costs or minimum 

run times. EEI argues that if 

transmission providers could not 

recover such costs through imbalance 


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401To the extent a transmission provider wishes 

to recover costs of additional regulation reserves 

associated with providing imbalance service, it 

must do so via a separate FPA section 205 filing 

demonstrating that these costs were incurred 

correcting or accommodating a particular entity’s 

imbalances. 

402See RockGen Energy, LLC, 100 FERC ¶ 61,261 

(2002) (setting for hearing, inter alia, whether 

proposed market proxy price is reliable, verifiable, 

and also indicative of the prevailing price in liquid 

non-redispatch markets in the region). 

403E.g., Entergy, Allegheny, Progress Energy, 

Public Power Council, South Carolina E&G, PGP, 

and Ameren. 

charges, they would not be able to 

recover them at all. 

Commission Determination 

687. The Commission concludes that 

it is appropriate to define incremental 

cost, for purposes of the tiered 

imbalance provisions adopted above, as 

the transmission provider’s actual 

average hourly cost of the last 10 MW 

dispatched to supply the transmission 

provider’s native load, based on the 

replacement cost of fuel, unit heat rates, 

start-up costs, incremental operation 

and maintenance costs, and purchased 

and interchange power costs and taxes, 

as applicable. 

688. In deriving such charges, we note 

that the Commission proposed in 

paragraph 244 of the NOPR that 

incremental cost be defined to include 

both additional energy and commitment 

costs. The Commission also sought 

comment on how additional demand 

and energy costs, such as redispatch, 

commitment, or additional regulation 

reserves, would be appropriately 

recovered if incurred in responding to 

imbalances. 

689. The Commission finds that it is 

appropriate, through the definition of 

incremental cost, to allow for recovery 

of both commitment and redispatch 

costs while excluding the cost recovery 

of additional regulation reserve costs. 

Commitment and redispatch costs shall 

be accommodated as a part of the hourly 

cost of the last 10 MW dispatch and in 

the start up cost portion of the 

definition. The Commission concludes 

that excluding additional regulation 

costs as a general matter is appropriate 

since much of those costs would be 

demand costs.401 We believe including 

charges for unit commitment costs (e.g., 

start-up and minimum load costs) and 

O&M costs is necessary to ensure that 

both energy and generation imbalance 

charges reflect the full incremental costs 

incurred by the transmission provider. 

We emphasize, however, that such costs 

should only be the additional costs 

incurred by the transmission provider 

due to the imbalance. If applicable, 

start-up costs should be allocated pro 

rata to the offending transmission 

customers based on cost causation 

principles. 

690. If the transmission provider 

elects to have separate demand charges 

assigned to customers for the purpose of 

recovering the cost of holding additional 

reserves for meeting imbalances, the 

transmission provider should file a rate 

schedule and demonstrate that these 

charges do not allow for double 

recovery of such costs. To address 

Entergy’s concern that the real-time 

regulation burden imposed by IPPs is 

similar to the real-time regulation 

burden imposed by loads, we will allow 

transmission providers to propose 

separate regulation charges for 

generation resources selling out of the 

control area and consider such 

proposals on a case-by-case basis. We 

believe that the other demand costs of 

providing imbalance service are already 

being provided under Schedule 3, 5, 

and 6 charges. 

691. In responding to Allegheny’s 

comments, we clarify that the definition 

of incremental cost is equally applicable 

to intermittent generator imbalance 

service as well as non-intermittent 

generator imbalance service. 

692. We do not believe it appropriate 

to require transmission providers to use 

market proxy pricing to calculate 

incremental costs in the pro forma 

OATT. The feasibility of using market 

proxies must be considered on a caseby-case basis, given the characteristics 

of each market. If proposed, the proxy 

price must represent a valid alternative 

to the incremental cost calculation, 

reflecting competitive, transparent and 

liquid conditions similar to those that 

would exist in the seller’s market.402

d. Inadvertent Energy Treatment 

NOPR Proposal 

693. The Commission proposed in the 

NOPR to continue to allow inadvertent 

energy to be treated differently from 

energy and generator imbalances, 

explaining that these two types of 

service are not comparable. The 

Commission noted that, given the nature 

of inadvertent energy and historical 

practices, transmission providers pay 

back inadvertent energy imbalances and 

that the Commission has accepted this 

practice as just and reasonable. The 

Commission sought comment on 

whether the current return-in-kind 

approach to inadvertent energy 

encourages leaning on the grid in times 

of shortage and, therefore, whether any 

reforms in this area are appropriate. The 

Commission asked whether pricing 

inadvertent energy at incremental cost 

(or some variant thereof) would be an 

appropriate disincentive and, if any 

reforms in this area are appropriate, 

whether they should be pursued under 

FPA section 215 as part of the review of 

reliability standards. 

Comments 

694. A number of commenters 

support continuing to allow inadvertent 

energy to be treated differently from 

energy and generator imbalances, 

agreeing that these two types of services 

are not comparable.403 Allegheny argues 

that this historical practice makes sense 

because the variables germane to 

inadvertent interchange are beyond the 

control of individual transmission 

providers and, therefore, are best 

addressed in the context of reliability. 

Entergy notes that transmission 

customers have some flexibility to 

mitigate the deviations between their 

schedules and the operation of their 

load in real-time, while control area 

interchange imbalances may involve the 

failure of control areas to match their 

scheduled inflows and outflows due to 

contingencies occurring even in a third 

control area. 

695. Northwest IOUs argue that there 

is no reason to think that there is abuse 

of one system leaning on another in 

regards to inadvertent energy, 

particularly in light of Control 

Performance Standards 1 and 2 and 

other protocols for balancing flows 

across interconnections. Public Power 

Council states that in-kind return of 

inadvertent energy between Balancing 

Authorities is governed by numerous 

agreements and tariffs that are designed 

to limit the ability of one system to lean 

on another. 

696. Sacramento states that the 

Commission expressed concern in other 

settings that generators may 

intentionally undergenerate during 

high-cost hours and make it up by 

overgenerating during low-cost hours 

under a return-in-kind approach. 

Sacramento contends that in kind 

means not only a return of energy, but 

a return of energy at like times and 

conditions and does not believe that this 

results in leaning. In its reply 

comments, Exelon requests that the 

Commission’s imbalance penalty rules 

explicitly prohibit the local utility 

Balancing Authority operator from 

relying on inadvertent energy to balance 

its affiliated generators’ schedules and 

thus obtaining a competitive advantage. 

697. Other commenters disagree that 

inadvertent energy should continue to 

be treated differently. Exelon expresses 

concern that in regions without 

organized markets there is the potential 


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404For example, the Commission noted that a 

transmission customer scheduling 100 MWh over 

an hour, but with a load of 120 MWh, would face 

an imbalance of 20 MW. The Commission 

questioned whether there should be a net charge if 

the customer also dispatched its generation to the 

same 120 MWh. Similarly, what if a transmission 

customer schedules 100 MWh, but has a load of 80 

MWh and dispatches its generation to 80 MWh? 

405 Imbalance Provisions Proceeding at 32,123 

note 19 (citing Niagara Mohawk, 86 FERC ¶ 61,009 

at 61,028). 

406E.g., Ameren, FirstEnergy, Xcel, Suez Energy 

NA, Morgan Stanley, Sacramento, TDU Systems, 

and Utah Municipals. 

for local utility balancing authority 

operators to seek to avoid paying 

deviation charges by favoring their own 

generators over merchant generators or 

by using inadvertent energy to balance 

their schedule. Exelon argues that a 

balancing authority operator could 

maintain system balance by choosing to 

order its affiliated generators to deviate 

from the schedule and thereby allow its 

affiliated generator to avoid deviation 

charges that the merchant generator 

could not avoid. If the local utility 

balancing authority operator relies on 

inadvertent energy to balance its 

affiliated generators’ schedules, Exelon 

contends it is using an option that is 

unavailable to other generation 

resources and obtains a competitive 

advantage. 

698. TDU Systems argue that energy 

imbalances and inadvertent interchange 

may occur for many of the same reasons, 

e.g., telemetry failure, meter error, 

generator governor response to system 

problems, human error, and under- or 

over-supply of generation. TDU Systems 

state that deviations between load and 

supply, whether in the form of energy 

imbalances or inadvertent interchange, 

require adjustment or compensation, but 

there is no reason why the form of that 

adjustment or compensation should be 

different among transmission users. 

TDU systems explain that NERC’s Final 

Report of the Control Area Criteria Task 

Force describes inadvertent interchange 

as one of the ‘‘strong incentives’’ driving 

the newer market participants, such as 

independent generators, to become 

control areas, and driving existing 

control area operators to retain their 

functions. 

699. TDU Systems explain that as the 

Commission acknowledged in Order No. 

2000, for transmission providers in RTO 

regions, unequal access to balancing 

options can lead to unequal access in 

the quality of transmission service. TDU 

Systems oppose deferring consideration 

of inadvertent interchange issues until 

the Commission’s order in the 

Mandatory Reliability Standards 

rulemaking proceeding in Docket No. 

RM06–16–000. TDU Systems argue that 

the Commission should place energy 

imbalance service on a footing as nearly 

comparable to inadvertent interchange 

as feasible by allowing like-kind 

exchanges of energy, at the incremental 

cost of their own supply portfolio, to 

remedy imbalances in lieu of the 

present paradigm of punitive charges. 

700. TDU Systems also argue that the 

Commission should require 

comparability between transmission 

providers and transmission customers 

by imposing charges for inadvertent 

interchange at the suppliers’

incremental cost. FirstEnergy believes 

that the Commission should establish a 

tiered penalty structure that, similar to 

the Bonneville method discussed by the 

Commission, levies penalties based on 

the severity of the inadvertent energy 

violation. TDU Systems state that 

currently there are no penalties for 

under-supply even when one control 

area could be deemed to be 

intentionally ‘‘leaning’’ on the grid to 

arbitrage energy market prices; but there 

should be. 

701. FirstEnergy argues that a 

nationwide process should be 

established by the Commission to 

eliminate regional differences in the 

treatment of inadvertent energy. 

Constellation asks the Commission to 

require that transmission providers 

specifically separate imbalances from 

inadvertent energy and closely track and 

report the two. 

Commission Determination 

702. As stated in the NOPR, the 

Commission finds that inadvertent 

energy is not comparable to energy and 

generation imbalances and, therefore, 

we will continue to allow inadvertent 

energy to be treated differently from 

energy and generation imbalances. 

Inadvertent energy represents the 

difference between a control area’s net 

actual interchange and the net 

scheduled interchange. It is caused by 

the combined effects of all the 

generation and loads in the control area 

and generation and loads outside of the 

control area. Variables affecting 

inadvertent interchange often depend 

on the actions or the omissions of 

utilities other than the individual 

transmission providers and are distinct 

from those resulting in energy and 

generation imbalances. 

703. We also note that management of 

inadvertent energy is needed to adhere 

to NAESB standards. Historically, 

transmission providers have paid back 

inadvertent interchange imbalances in 

kind, which has not, as a general matter, 

proven to be problematic. Our primary 

concern with respect to inadvertent 

energy is to avoid incentives that could 

degrade reliability. To date, the returnin-kind approach has proven to be 

adequate as a general matter. However, 

if there is evidence that it is no longer 

sufficient to maintain reliability, or is 

allowing certain entities to lean on the 

grid to the detriment of other entities, 

the Commission has authority under 

FPA section 215 to direct the ERO to 

develop a new or modified standard to 

address the matter. 

e. Netting/Crediting of Energy and 

Generator Imbalances 

NOPR Proposal 

704. In the NOPR, the Commission 

sought comment on whether or not it is 

appropriate to allow a transmission 

customer to net energy and generator 

imbalances for a particular transaction 

within a single control area to the extent 

they offset.404 The Commission asked 

whether the potential to allow netting 

for offsetting imbalances contradicts the 

principle of encouraging good 

scheduling practices. The Commission 

sought further comment on what would 

be a reasonable percentage to net 

without concerns that allowing such 

netting would lead to reliability 

concerns from using unscheduled 

transmission or would cause redispatch 

costs by the transmission provider. 

705. The Commission also proposed 

to add provisions to schedule 4—Energy 

Imbalance Service and schedule 9—

Generator Imbalance Service of the pro 

forma OATT to reflect the Commission’s 

policy that a transmission provider may 

only charge a transmission customer for 

either hourly generator imbalances or 

hourly energy imbalances for the same 

imbalance, but not both.405 The 

Commission explained that this policy 

only applies to a transmission customer 

that otherwise would be charged for 

both generator imbalances and energy 

imbalances for the same imbalance 

occurring within the same control area. 

Comments 

706. A number of entities believe that 

transmission customers should be 

permitted to net energy and generator 

imbalances to the extent that such 

imbalances offset.406 Ameren and 

FirstEnergy assert that netting better 

reflects the impact of imbalances. 

Morgan Stanley argues that allowing 

such netting provides a clear 

competitive benefit because it would 

allow competitive suppliers to offer a 

load following service in competition 

with the transmission provider. 

Sacramento agrees that netting of 

offsetting imbalances should be allowed 


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407E.g., Entergy, Pinnacle, Indianapolis Power, 

and Indicated New York Transmission Owners. 

provided the transmission customer 

relies on reasonable load forecasts. 

707. Utah Municipals and Steel 

Manufacturers Association argue that 

the Commission should impose charges 

based on netted imbalances, both for 

each customer and across the system as 

a whole. PGP contends that there is no 

reason to charge for both imbalances if 

a generator overruns during the same 

hour when a load overruns, so long as 

the overruns cancel out within a given 

control area. Steel Manufacturers 

Association contends that the 

Commission should incorporate control 

area-wide netting of imbalances to 

ensure that penalties are only assessed 

on significant imbalances and energy 

imbalance charges do not become a 

windfall profit center for utilities. Utah 

Municipals suggest that the Commission 

provide that all imbalances be netted for 

each hour and that penalties (charges 

above or credits below actual costs) be 

imposed only when the system as a 

whole is out of balance by more than a 

de minimis amount and, even then, only 

on those customers whose imbalances 

fall in the same direction as the system 

imbalance. Utah Municipals note that 

Sierra Pacific has established a similar 

imbalance mechanism, which appears 

to be working well in its control area. 

708. TDU Systems argue that the 

netting rules should be sufficiently 

flexible to allow individual customers to 

net their transactions within an hour, a 

day, a week or a month, so long as the 

results keep the transmission provider 

economically whole. TDU Systems state 

that the Commission should not impose 

a cap on the quantity of netting allowed 

unless the transmission provider is able 

to demonstrate that good system 

performance requires such a cap. 

Ameren suggests that the Commission 

use a tiered system for determining 

when imbalances can be netted, but 

argues that a transmission customer 

should not be allowed to net offsetting 

imbalances elsewhere on the system if 

the imbalance has the potential to have 

a significant reliability impact. 

709. FirstEnergy and Utah Municipals 

contend that both point-to-point and 

network transactions should be eligible 

for netting. Utah Municipals and 

NRECA in their reply comments note 

that the Commission’s reference to ‘‘a 

particular transaction’’ does not mesh 

with the needs and practices of network 

customers, who do not attempt to match 

portions of their total hourly loads with 

particular resources or ‘‘transactions.’’

Utah Municipals argue that the 

Commission’s proposal should be 

modified to make clear that such 

customers should be permitted to net 

energy and generator imbalances within 

a single control area to the extent they 

offset, with no requirement that the 

imbalances be part of a single 

‘‘transaction.’’

710. Other commenters, however, 

contend that transmission customers 

should not be permitted to net energy 

and generator imbalances.407 For 

example, Entergy and Pinnacle believe 

that to permit netting of energy and 

generator imbalances is to undercut the 

very purpose of the imbalance 

provisions, which is to provide 

adequate incentives to schedule 

correctly and in accordance with good 

utility practice. Pinnacle asserts that, 

depending upon the location, energy or 

generator imbalances could create 

reliability or economic problems for 

specific areas of the system and it is 

important that the transmission operator 

know what is happening on its system 

and for the customer to adhere to 

accurate scheduling. SPP argues that 

allowing netting of imbalance energy 

between generation and load would 

allow price arbitrage that would be 

unjust and unreasonable. Indicated New 

York Transmission Owners assert that 

positive and negative imbalances do not 

actually offset, as the NOPR would 

suggest, but rather each imbalance 

independently places stress on the 

transmission system. Duke states on 

reply that, although several commenters 

support netting imbalances, not one 

entity supporting such netting has put 

forth a workable proposal for how to 

implement such netting where multiple 

generators are serving multiple loads. 

711. Entergy believes that 

independent generators must take full 

responsibility for meeting their own 

schedules, including making 

adjustments to their schedules to 

conform them to their operation in realtime. Entergy argues that a netting 

approach, however, would provide an 

incentive for a generator to overgenerate above its schedule if its load 

proves to be greater than expected in 

real-time. Entergy argues that allowing 

the netting of these imbalances will 

result in the virtual elimination of 

transmission schedules. 

712. In instances in which 

transmission customers intentionally 

game the transmission system through 

netting, FirstEnergy contends that the 

transmission provider should have the 

ability to apply punitive measures 

through a Commission-mandated 

penalty process. FirstEnergy states that 

there appears to be no clear cut number 

which defines the boundary between 

‘‘good’’ netting and ‘‘bad’’ netting 

associated with reliability issues and 

additional redispatch cost. During 

periods when transmission constraints 

exist, Entergy contends that it may in 

fact be ramping up some generators to 

respond to imbalances while ramping 

down other generation to respond to 

other imbalances at exactly the same 

time and, therefore, it is incorrect to 

assume that over-generation supplied by 

one IPP accompanied by undergeneration from another IPP, even 

simultaneously, will have no 

operational effect or impose no costs on 

a transmission provider. 

713. Allegheny believes that allowing 

netting of hourly deviations inside the 

first deviation band on a monthly basis 

would not allow for full recovery of 

imbalance costs because balances that 

occur in on-peak periods cost more than 

imbalances that occur during off-peak 

periods. Allegheny contends that 

deviations within the first band should 

be measured and settled financially on 

an hourly or, at least, an on-peak/offpeak basis, rather than allowing 

deviations during one part of the month 

to be offset by deviations in another part 

of the month. Indianapolis Power & 

Light Company argues that the 

imbalance volume could be within the 

allowed bandwidth tolerance, but still 

be significant enough to allow for the 

energy market participant to make 

money off of the price difference. 

714. Entergy also contends that a 

crediting mechanism for generator 

imbalances would be not appropriate. 

Entergy asserts that such a credit would 

result in indifference by generators by 

largely immunizing them from the costs 

resulting from their imbalances and, as 

a consequence, produce economic 

inefficiencies and a potential threat to 

system reliability. Entergy argues that 

the current method, which provides an 

incentive to generators to control their 

own imbalances, is appropriate because 

generators have a desire to accurately 

schedule to avoid imbalances. Entergy 

argues that a non-offending generator in 

one hour can be an offending generator 

in the next hour and that the credit will 

bankroll generators so that penalty 

payments in one hour will be offset and 

paid for by penalty receipts in another 

hour. 

Commission Determination 

715. The Commission recognizes that 

there is a trade off between the 

competitive benefits of reducing 

imbalance charges, including allowing 

transmission customers to net energy 

and generation imbalances, and the 

reliability implications of the 

transmission provider needing to plan 

to accommodate such imbalances. 


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408E.g., TVA, South Carolina E&G, and 

International Transmission. 

409 International Transmission provides the 

example that a large generator with scheduled 

output of 100 MW for an hour might stay at zero 

for the first 50 minutes of the hour and then 

generate 600 MW during the last ten minutes. 

410See Entergy Services, Inc., 102 FERC ¶ 61,014 

(2003) and Entergy Services, Inc., 111 FERC 

¶ 61,314 (2005). 

411See Order No. 2003 at P 335. 

412See pro forma LGIA Article 4.3.1 

Allowing transmission customers to net 

imbalances would further comparability 

between the transmission provider’s 

dispatch and the transmission 

customers serving load. However, 

netting and crediting could lessen the 

incentive for accurate scheduling and 

resulting energy or generator imbalances 

could create reliability or economic 

issues for specific areas of the system if 

the transmission provider cannot 

adequately plan for such imbalances. 

716. In weighing these tradeoffs, the 

Commission concludes that for both 

energy and generator imbalance services 

it is not appropriate to require 

transmission providers to allow netting 

of imbalances outside of the tier one 

band. We agree that netting can cause 

problems because netting would lessen 

the incentive for transmission customers 

to schedule accurately, and inaccurate 

schedules, in turn, could require actions 

by the transmission provider even when 

the imbalances offset. Where 

transmission constraints exist, a 

transmission customer whose load and 

generation was on net equal could still 

have an effect on the transmission 

system if, as Entergy contends, some 

generation is ramping up to respond to 

some imbalances while other generation 

is ramping down at exactly the same 

time. Similarly, where transmission 

constraints exist, if one IPP has a 

positive deviation from its schedule 

while another IPP has a corresponding 

negative deviation from its schedule, the 

transmission provider could need to 

ramp up generation in one area while 

simultaneously ramping down 

generation in another area. Further, we 

believe that flexible scheduling 

deadlines should allow transmission 

customers to change their schedules 

such that their loads can be accurately 

met and implementation of the tiered 

imbalance bands will ensure that 

charges corresponding to imbalances are 

just and reasonable. 

f. Intra Hour Netting 

NOPR Proposal 

717. Under the current pro forma 

OATT, energy imbalances occur when 

there is a difference between the 

scheduled and the actual delivery of 

energy to a load located within a control 

area aggregated over a single hour. As a 

result, if a transmission customer is 

under its scheduled level for the first 

half of a given hour, but over its 

schedule the second half of the hour, 

there would be no imbalance charge. 

The Commission did not address intra 

hour netting in the NOPR. 

Comments 

718. Several commenters argue that 

the Final Rule should address withinhour deviations that occur when 

generator imbalances are calculated on 

an integrated hour basis.408 If the 

generator imbalance is measured over 

an integrated hour, as is typical of the 

current practice, TVA asserts that 

significant intra-hour swings may be 

masked. 

719. South Carolina E&G states that 

generators, unable to ramp precisely to 

the 15-minute schedules, often 

undergenerate in the initial part of the 

hour, then overgenerate in later parts of 

the hour, in order to integrate closer to 

the schedule when settled over the 

entire hour. South Carolina E&G 

contends these intentional swings 

burden the balancing authorities who 

are charged with continuously keeping 

Area Control Error within predefined 

limits. International Transmission 

argues that intentional swings in output 

can be quite severe, imposing 

operational strains on the system, 

negatively impacting the control area’s 

ability to meet NERC Control 

Performance Standards, and potentially 

jeopardizing reliability.409 Entergy 

agrees that settling hourly energy 

imbalances with generators does not 

provide adequate incentives for 

generators to schedule and dispatch 

accurately within the hour. Entergy 

asserts that generators have imposed 

significant moment to moment swings 

within the hour requiring it to deploy its 

regulating reserves in response. Entergy 

states that it has been increasingly 

difficult to meet NERC’s operating 

criteria for control area performance 

without committing, and incurring the 

costs for, additional regulating reserves. 

TVA contends that all generators should 

be required to ensure that the 

instantaneous generation level equals 

the scheduled output. International 

Transmission asks that the imbalance 

provisions in the Final Rule address this 

situation by either specifying penalties 

that may be assessed for within-hour 

variations or advising that transmission 

providers may implement their own 

penalties to the extent that within-hour 

variations cause operational difficulties. 

720. South Carolina E&G contends 

that allowing generator imbalance 

settlements over a shorter period, such 

as at 15-minute intervals, together with 

the proposed tiered charges for 

imbalances, would provide better, more 

refined incentives for generators to more 

closely match their scheduled deliveries 

and would help balancing authorities 

reduce Area Control Error excursions. 

TVA suggests generator imbalances be 

measured on ten-minute intervals rather 

than integrated over an hour. These tenminute imbalances would not be netted 

against other imbalance intervals, so as 

to avoid the problem of encouraging 

undergeneration followed by 

overgeneration and vice versa. In 

addition to having generator imbalance 

charges for generation outside the 

operating bands, TVA argues that there 

should be a separate charge assessed 

based on the peak generator imbalance 

between the scheduled and actual 

generation recorded instantaneously 

during the clock hour to provide a 

further incentive for proper generator 

scheduling. 

721. Pinnacle and Utah Municipals 

assert that a transmission provider 

should only charge hourly generator 

imbalances or hourly energy imbalances 

for the same imbalance. PGP argues that 

customers should pay only one charge 

for the net imbalance that occurs within 

a single control area, either energy or 

generation, unless congestion occurs 

inside a control area that requires 

redispatch. 

Commission Determination 

722. The Commission concludes that 

it is appropriate to maintain the status 

quo of aggregating net generation over 

the hour in the pro forma OATT. 

Requests by transmission providers to 

adopt a shorter interval will continue to 

be considered on a case-by-case basis.410

The Commission acknowledges that 

shorter intervals may be appropriate in 

particular circumstances and, for this 

reason, declined to use a clock-hour 

interval in the Large Generator 

Interconnection Final Rule.411 There, 

the Commission permitted use of an 

interval ‘‘consistent with the scheduling 

requirements of the Transmission 

Provider’s Commission-approved Tariff 

and any applicable Commissionapproved market structure.’’ 412

Allowing transmission providers to 

continue to propose alternative intervals 

for purposes of the pro forma OATT 

imbalance provisions is therefore 

appropriate provided that such 

proposals are consistent with relevant 

market structures. 


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413See Carolina Power & Light Co., 103 FERC 

¶ 61,209 at P 25 (2003) (CP&L); Entergy Svcs., 105 

FERC ¶ 61,319, reh’g denied, 109 FERC ¶ 61,095 at 

P 65–66 (2004). 

414See Carolina Power & Light Co., 97 FERC 

¶ 61,048 at 61,279 (2001). 

415 Id. 

g. Distribution of Penalty Revenues 

Above Incremental Cost 

NOPR Proposal 

723. The Commission also sought 

comment in the NOPR regarding the 

treatment of revenues the transmission 

provider receives above the cost of 

providing the imbalance service. 

Comments 

724. Various commenters state that 

the transmission provider should retain 

any amounts above the incremental cost 

of providing imbalance service. Ameren 

and Constellation argue such revenues 

should serve as a contribution towards 

the fixed costs of providing this service. 

Entergy argues that premium charges 

would compensate it for the 

administrative costs of maintaining an 

organization capable of providing this 

purchase and sales function and provide 

generators with an incentive to avoid 

mismatches between scheduled 

quantities and actual deliveries to 

Entergy. Entergy states that the 

Commission has previously recognized 

that these generator imbalance charges 

are analogous to the economy power 

rates that have historically included a 

percentage adder for out-of-pocket costs 

to recover difficult-to-quantify costs. 

725. On the other hand, FirstEnergy 

states that the additional revenue 

derived from charges above incremental 

costs should be provided to generators 

and/or customers able to regulate load 

that provided the redispatch, 

commitment, or additional regulation 

reserves. Utah Municipals contend that 

the Commission should credit revenues 

from charges above incremental costs to 

accurately-scheduling customers, rather 

than to the transmission provider. Utah 

Municipals argue that the penalty 

portion of incremental and decremental 

charges and rates could be credited back 

to all transmission customers who incur 

imbalance charges and whose schedules 

fell within the first deviation band for 

that hour. Progress Energy suggests that 

all imbalance revenues above the cost of 

providing the imbalance should be 

distributed to all non-offending 

transmission customers, based on the 

weighted amount of each non-offending 

transmission customer’s usage of the 

transmission provider’s transmission 

system. TAPS and TDU Systems ask on 

reply that penalty revenues not be 

earmarked for retail customers. 

726. Morgan Stanley believes that 

imbalance charges should be ‘‘keep 

whole’’ charges calculated and designed 

to reimburse whoever remedied 

whatever problem the imbalance caused 

while leaving the transmission provider 

financially indifferent. 

Commission Determination 

727. In this Final Rule, the 

Commission has reformed existing 

imbalance provisions to reduce the 

variety of different methodologies used 

for determining imbalance charges and 

ensure that the level of the charges 

provide appropriate incentives to keep 

schedules accurate without being 

excessive. We also believe that 

transmission providers should have a 

consistent method of treating revenues 

received through imbalance penalties or 

charges that are in excess of incremental 

cost. The Commission has previously 

required transmission providers with 

significant imbalance penalties to 

develop a mechanism to credit penalty 

revenues to non-offending transmission 

customers.413 This was intended to 

remove the incentive of the 

transmission provider to hinder the 

development of other imbalance 

services that do not rely on penalties.414

We believe it is appropriate to maintain 

the requirement that transmission 

providers credit revenues in excess of 

incremental costs. Therefore, as part of 

their compliance filings in this 

proceeding, transmission providers are 

required to develop a mechanism for 

crediting such revenues to all nonoffending transmission customers 

(including affiliated transmission 

customers) and the transmission 

provider on behalf of its own customers. 

Such a distribution of penalty revenues 

recognizes that transmission providers 

bear the responsibility to correct 

imbalances and often use their own 

facilities to do so. 

728. We acknowledge that in the 

CP&L decision, the Commission 

declined to allow the transmission 

provider to allocate a share of imbalance 

penalty revenues to itself as a user of the 

transmission system on behalf retail 

customers. Given the reforms to the pro 

forma OATT imbalance provisions 

adopted in this Final Rule, we believe 

the circumstances presented in that case 

are no longer applicable. There, the 

Commission based its holding on its 

understanding that the high imbalance 

penalties imposed by the transmission 

provider were an interim measure that 

were intended to be in place only until 

an imbalance market was developed.415

In this Final Rule, we are adopting 

imbalance charges that are closely 

related to incremental cost and therefore 

minimize any incentive on the part of 

the transmission provider to rely on 

penalty revenues rather than seeking 

other methods of encouraging accurate 

scheduling. Under these circumstances, 

there remains no reason to exclude the 

transmission provider from receiving an 

appropriate share of penalty revenues. 

3. Credits for Network Customers 

729. In Order No. 888, the 

Commission established that network 

customers should be eligible for credits 

for customer-owned transmission 

facilities under certain circumstances. 

Specifically, section 30.9 of the pro 

forma OATT states that a network 

customer owning existing transmission 

facilities that are integrated with the 

transmission provider’s transmission 

system may be eligible to receive cost 

credits against its transmission service 

charges if the network customer can 

demonstrate that its transmission 

facilities are integrated into the plans or 

operations of the transmission provider 

to serve its power and transmission 

customers. Section 30.9 also states that 

new facilities are eligible for credits 

when the facilities are jointly planned 

and installed in coordination with the 

transmission provider. 

NOPR Proposal 

730. In the NOPR, the Commission 

proposed severing the link in the pro 

forma OATT between joint planning 

and credits for new facilities owned by 

network customers because such linkage 

can act as a disincentive to coordinated 

planning. The Commission proposed 

deleting from section 30.9 the language 

that permits transmission providers to 

refuse crediting for new network 

customer-owned facilities that are not 

part of its planning process, and adding 

language that puts a greater emphasis on 

comparability. Specifically, the 

Commission proposed that the network 

customer shall receive credit for 

transmission facilities added subsequent 

to the effective date of the Final Rule in 

this proceeding provided that such 

facilities are integrated into the 

operations of the transmission 

provider’s facilities and if the 

transmission facilities were owned by 

the transmission provider, they would 

be eligible for inclusion in the 

transmission provider’s annual 

transmission revenue requirement as 

specified in Attachment H of the pro 

forma OATT. 

731. In the NOPR, the Commission 

also declined to allow transmission 

providers as part of this proceeding to 

automatically add costs of credits to the 

transmission provider’s cost of service. 

However, the Commission stated that a 


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416Order No. 888 at 31,742; Order No. 888–A at 

30,271. 

417E.g., Allegheny, East Texas Cooperatives, 

ELCON, Exelon, FMPA, MDEA, MidAmerican, 

MISO, Suez Energy NA, Tacoma, TAPS, and Utah 

Municipals. 

418E.g., Allegheny, EEI, Exelon, MISO, Nevada 

Companies, South Carolina E&G, Suez Energy NA, 

and Tacoma. 

419E.g., Allegheny, Ameren, and MidAmerican. 

420E.g., EEI, MidAmerican, and Nevada 

Companies. 

421E.g., FMPA, NRECA, and TAPS. 

422E.g., East Texas Cooperatives, NRECA, TAPS, 

and TDU Systems. 

transmission provider may propose to 

add an automatic adjustment clause to 

its rates in a filing submitted under 

section 205 of the FPA. The 

Commission also explained that it 

would not propose to make credits 

generically available to point-to-point 

customers that own transmission 

facilities, but clarified that if some 

facilities owned by a point-to-point 

customer meet all the criteria for credits, 

consistent with the Commission’s 

statement in Order No. 888, the 

Commission would address such 

situations on a fact-specific, case-bycase basis.416

a. Severance of Credits and Planning 

Comments 

732. The NOPR proposal to sever the 

link between transmission credits and 

joint planning by eliminating the jointplanning requirement for credits for 

new facilities constructed by network 

customers is supported by a crosssection of the industry.417 Exelon asserts 

that linking credits to network 

customers with coordinated planning 

simply creates an incentive for the 

transmission provider to avoid 

coordinated planning with the network 

customers so that the provider can avoid 

providing credits. In addition, the 

criterion of ‘‘jointly planned’’ with the 

transmission provider provides little or 

no value for discerning what facilities 

should qualify for crediting treatment. 

Further, Exelon argues, tying credits to 

joint planning is no longer necessary 

because the Commission’s regional 

planning initiatives will insure that 

most, if not all, newly constructed 

facilities will be jointly planned. While 

EEI disagrees that the joint planning 

provision has acted as a disincentive to 

joint planning, it agrees that the 

coordinated planning initiatives in the 

NOPR has made the link unnecessary. 

733. FMPA also argues that the link 

between credits and planning 

discourages joint planning because 

companies can avoid transmission rate 

credits, often for competitors, by simply 

refusing to jointly plan. FMPA asserts 

that it makes no sense to create 

economic disincentives to joint 

planning. According to these 

commenters, transmission lines cannot 

be built without some exchange of 

information; the joint planning link may 

discourage the most productive 

exchange and can create needless and 

non-productive disputation over 

whether joint planning did or should 

have taken place. 

734. PGP points out, however, that 

credits for new facilities can only result 

from joint planning, because new 

facilities must be interconnected with 

the existing grid, and planning studies 

are necessary for that to happen. 

NorthWestern requests that the 

Commission reconsider its proposal to 

allow crediting of customer-owned 

facilities that have not been jointly 

planned with the transmission provider. 

NorthWestern contends that allowing 

the construction of network facilities 

and making a judgment after the fact is 

inefficient and will result in protracted 

litigation and facilities that do not serve 

the overall grid as efficiently as planned 

facilities. PNM–TNMP contends that the 

Commission’s proposed action to ‘‘sever 

the link’’ will excuse the network 

customer from the coordinated planning 

process and can only operate at crosspurposes with the coordinated 

transmission planning goal that is 

addressed in the planning sections of 

the NOPR. 

Commission Determination 

735. The Commission adopts the 

NOPR proposal to sever the link in the 

pro forma OATT between joint planning 

and credits for new facilities owned by 

network customers. The proposal 

received broad industry support, and we 

agree with these commenters that the 

link between credits for new facilities 

and the requirement for joint planning 

can act as a disincentive to coordinated 

planning, which is contrary to the 

Commission’s original objective in 

adopting the provision. A transmission 

provider has an incentive to deny 

coordinated planning in order to avoid 

granting credits for customer-owned 

transmission facilities. 

736. We find that arguments against 

the proposal are largely theoretical and 

do not adequately take into account the 

coordinated planning provisions 

proposed in the NOPR. The coordinated 

planning initiatives that the 

Commission is adopting in the Final 

Rule will ensure that most, if not all, 

transmission facilities are planned on a 

coordinated basis, making it 

unnecessary to retain this provision of 

section 30.9. 

b. The New Test to Determine Eligibility 

for Credits 

737. Comments support the test for 

new facilities proposed in the NOPR.418

Some argue that the test for network 

customer credits should continue to be 

whether the network customer’s 

facilities provide capability and 

reliability benefits to the grid—the same 

standard that would apply to inclusion 

of the facilities in the transmission 

provider’s cost of service if the 

transmission provider constructed the 

facilities.419 MidAmerican states that 

further clarification of this point in the 

Final Rule would be beneficial in 

minimizing disputes over this issue. 

Likewise, MidAmerican asks the 

Commission to clarify in the Final Rule 

that such credit can be applied only to 

network customers taking OATT service 

and not to transmission customers that 

are under non-OATT (i.e., grandfathered 

bundled agreements) contracts. PGP 

supports the new rules for granting 

credits to network customers, but argues 

implementation details should be left 

up to individual transmission providers. 

738. Although several transmission 

providers support the continued use of 

the integration test,420 other 

commenters representing municipal and 

public power interests ask that the 

Commission reconsider or clarify its 

application.421 Some commenters argue 

that given the Commission’s current 

interpretation of ‘‘integration’’ for 

transmission credit purposes and the 

historical application of the test, 

retaining any integration requirement 

for existing or new facilities conflicts 

with comparability or constitutes undue 

discrimination.422 TDU Systems argue 

that the integration standard has 

encouraged discriminatory behavior by 

allowing transmission providers to 

charge network customers for 

transmission provider facilities 

constructed to serve the transmission 

provider’s native load, while refusing to 

pay the network customer for 

comparable customer-owned 

transmission facilities. TDU Systems 

further argue that the integration test 

has resulted in a form of ‘‘and’’ pricing 

since the TDU Systems, as network 

transmission service customers, remain 

obligated to pay their load ratio share of 

the full transmission revenue 

requirement of the transmission 

provider’s system, including the cost of 

transmission facilities built to serve the 

transmission provider’s own loads. 

739. NRECA questions the 

Commission’s statement in the NOPR 

that, in order to satisfy the integration 


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423NRECA further notes that proposed OATT 

section 30.9 does not include these additional 

‘‘benefits’’ and ‘‘relied upon’’ requirements. NRECA 

argues that these requirements cannot be part of the 

section 30.9, since regulatory preambles cannot 

vary the words of the rule, citing Wyoming Outdoor 

Council v. U.S. Forest Service, 165 F.3d 43, 53 (D.C. 

Cir. 1999) (‘‘[L]anguage in the preamble of a 

regulation is not controlling over the language of 

the regulation itself’’). 

424 108 FERC ¶ 61,084 (2004), reh’g denied, 111 

FERC ¶ 61,189 (2005). 

425 114 FERC ¶ 61,027 at P 42 (2006), appeal 

docketed, No. 06–1090 (D.C. Cir. Mar. 10, 2006). 

426NOPR at P 256. 

427 Id. 

428E.g., APPA, FMPA, and NRECA. 

429Entergy. 

430E.g., APPA, East Texas Cooperatives, FMPA, 

and NRECA. 

431NRECA compares North East Texas Electric 

Cooperative, Inc., 108 FERC ¶ 61,084 (2004), reh’g 

denied, 111 FERC ¶ 61,189 (2005) (finding 

transmission provider facilities integrated and 

rolling in their cost over transmission provider 

objection) with Mansfield Municipal Electric 

Department v. New England Power Co., 97 FERC 

¶ 61,134 (2001), reh’g denied, 98 FERC ¶ 61,115 

(2002) (finding transmission provider facilities not 

integrated and rolling out their cost over 

transmission provider objection). 

432MDEA cites Florida Power and Light Co., 116 

FERC ¶ 61,013 (2006), and notes that the 

Commission applied principles of comparability to 

a transmission provider’s existing facilities. 

standard, a customer ‘‘must demonstrate 

that its facilities not only are integrated 

with the transmission provider’s system, 

but also provide additional benefits to 

the transmission grid in terms of 

capability and reliability and can be 

relied on by the transmission provider 

for the coordinated operation of the 

grid.’’ 423 According to NRECA, that 

statement identifies three nominal 

requirements for customer facilities—

integration, benefits and ‘‘relied 

upon’’—as compared to the one nominal 

requirement for transmission provider 

facilities—integration. This is 

fundamentally inconsistent with 

comparability, NRECA continues, as the 

Commission seems to recognize in its 

rationale for adding the comparability 

requirement to new facilities. 

740. NRECA further argues that the 

NOPR failed to distinguish the proposed 

new standard in revised section 30.9 

from the Commission’s recent decision 

in North East Texas Electric 

Cooperative, Inc.,424 which found 

transmission provider facilities 

integrated on the grounds that a 

showing of any degree of integration is 

sufficient, rejected a ‘‘benefits’’

requirement, and did not consider a 

‘‘relied upon’’ requirement. East Texas 

Cooperatives argues that the 

Commission’s decision in East Texas 

Electric Cooperative, Inc. v. Central and 

South West Services, Inc.,425 applied an 

integration requirement for customer 

facility credits that was different and 

stricter than the standard applied to a 

transmission provider’s facilities. 

741. Regarding the application of the 

integration component, FMPA argues 

that, in order to avoid continued 

discrimination, it is important that the 

Commission reaffirm that ‘‘additional 

benefits to the transmission grid in 

terms of capability, delivery options, 

and reliability’’ 426 are benefits, 

regardless whether the transmission 

customers or the transmission provider 

(or others) benefit. Similarly, FMPA 

continues, the requirement that facilities 

must ‘‘be relied upon for the 

coordinated operation of the grid’’ 427

must equally include operations that 

serve transmission providers, customers 

or others. 

742. Comments on the comparability 

component of the proposed credits test 

for new facilities range from several 

requesting that the Commission adopt a 

comparability-driven analysis 428 to one 

asking the Commission to eliminate the 

comparability component in favor of an 

integration-only analysis.429

743. Some commenters argue that 

eligibility for credits should turn in the 

first instance on the comparability 

standard set forth in the NOPR, 

otherwise the proposal does not 

eliminate undue discrimination.430

NRECA argues that this requirement 

does not abandon integration because 

current Commission policy requires a 

Transmission Provider’s facilities to be 

integrated for their cost to be rolled in 

to the transmission provider’s annual 

transmission revenue requirement.431

APPA would apply an integration test 

only if the transmission facilities for 

which the customer seeks credits are 

found not to be eligible under this 

comparability standard. 

744. TAPS states that, by eliminating 

the integration test and simply 

providing that customer-owned 

facilities would be eligible for credits to 

the extent they would be included in 

the transmission provider’s rate base if 

they were owned by the transmission 

provider (i.e.comparability test), the 

Commission would avoid litigation over 

what (if anything) the separate 

‘‘integration’’ requirement adds in the 

proposed formulation. If the integration 

terminology is retained in section 30.9, 

TAPS argues that the Commission at 

least should clarify that the new 

integration test is truly different from 

the old integration test and cannot 

properly be read as limiting the 

comparability requirement and that the 

Commission will not follow precedents 

developed in credits cases decided 

under the original section 30.9. 

745. To provide a comparability 

baseline and eliminate the need for an 

integration test, APPA recommends that 

transmission providers provide a 

detailed inventory of the existing 

facilities owned by transmission 

provider and network transmission 

customers that are included in their 

annual transmission revenue 

requirement. Network transmission 

customers could use the inventory, 

which would be updated annually, to 

assess whether they currently own 

transmission facilities comparable to 

those included in the transmission 

provider’s transmission rate base, or to 

third-party transmission facilities for 

which credits are being provided. 

746. MDEA argues that proposed 

section 30.9 appears contrary to 

comparability principles by imposing a 

standard for transmission facilities 

owned by customers that is more 

stringent than the one applied to the 

transmission provider’s own facilities. 

In MDEA’s view, the NOPR proposal is 

inconsistent with prior Commission 

precedent to the extent comparability is 

not required in evaluating eligibility of 

existing facilities owned by 

transmission providers for cost 

recovery.432

747. TDU Systems ask that the 

Commission clarify that the 

comparability prong will be aggressively 

enforced. For example, TDU Systems 

request that the Commission consider a 

bright-line voltage criterion to address 

comparability, rather than leaving it to 

the transmission provider’s discretion as 

to whether the facilities would be 

eligible for inclusion in the transmission 

provider’s annual transmission revenue 

requirement. 

748. Arguing against the use of the 

comparability component, Entergy 

contends that it could cause significant 

confusion, and should in no way change 

the basic requirements needed to show 

integration of network customer 

facilities. According to Entergy, a 

network customer should be entitled to 

credits only when the transmission 

provider cannot meet the transmission 

provider’s firm obligations without the 

customer’s transmission facilities. 

749. On reply, MDEA states that the 

principle of comparability requires that 

there be no distinction based on 

ownership or between existing and new 

facilities. It further asserts that Entergy 

attempts to draw a distinction between 

customer-owned transmission facilities 

needed by the transmission provider to 

meet the transmission provider’s 

obligations to native load and firm 

transmission customers (for which 

credits should be available) and 


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433E.g., Entergy, Exelon, and Utah Municipals. 

434See NOPR at P 256. 

435See e.g., North East Texas Electric 

Cooperative, Inc., 108 FERC ¶ 61,084; East Texas 

Electric Cooperative, Inc. v. Central and South West 

Services, Inc., 114 FERC ¶ 61,027. 

436The integration standard, in brief, requires that 

to be eligible for credits under pro forma OATT 

section 30.9, the customer must demonstrate that its 

facilities not only are integrated with the 

transmission provider’s system, but also provide 

additional benefits to the transmission grid in terms 

of capability and reliability and can be relied on by 

the transmission provider for the coordinated 

operation of the grid. Southwest Power Pool, Inc., 

108 FERC ¶ 61,078 at P 17 (2004) (citing Order No. 

888–A at 30,271), reh’g denied, 114 FERC ¶ 61,028 

(2006). This policy is premised on the principle that 

‘‘just as the transmission provider cannot charge the 

customer for facilities not used to provide 

transmission service, the customer cannot get 

credits for facilities not used by the transmission 

provider to provide service.’’ Id. at P 20 (citing 

Order No. 888–A at 30,271 & n. 277); accord East 

Texas Coop., Inc. v. Central & South West Services, 

Inc., 108 FERC ¶ 61,079 at P 28 (2004), reh’g denied, 

114 FERC ¶ 61,027 (2006); Southern California 

Edison Co., 108 FERC ¶ 61,085 at P 10 (2004); 

Northern States Power Co., 87 FERC ¶ 61,121 at 

61,488 (1999); Florida Municipal Power Agency v. 

Florida Power & Light Co., 74 FERC ¶ 61,006 at 

61,010 (1996), reh’g denied, 96 FERC ¶ 61,130 at 

61,544–45 (2001), aff’d sub nom. Florida Municipal 

Power Agency v. FERC, 315 F.3d 362 (D.C. Cir. 

2003). 

437E.g., APPA, FMPA, MDEA, NRECA, and 

TAPS. 

facilities that a network customer 

decides that it needs to meet its 

obligations. Entergy argues that credits 

should be available only for the former 

type of facility. According to MDEA, 

there is no justification for the 

distinction Entergy seeks to draw or the 

standard it proposes to apply. Network 

customers pay a full load ratio share of 

the embedded costs of the transmission 

grid, based on the premise that the 

entire grid is available and required to 

support network loads. In this regard, 

there is no difference between Entergy’s 

native load and network customer loads. 

Transmission facilities required to meet 

network customer needs by definition 

are required to meet grid needs, 

provided that such facilities are 

integrated with the transmission 

network. 

750. Several commenters ask the 

Commission to consider crediting 

mechanisms other than the NOPR 

proposal.433 For example, Entergy and 

Exelon contend that new facilities 

should be eligible for credit only if 

determined through the regional 

planning process that such new 

facilities are needed, i.e., that a 

measurable system capability or 

reliability benefit is provided. In their 

view, this will avoid litigation of cases 

addressing questions of integration. 

Utah Municipals argue that the 

Commission should not discount the 

potential evidentiary value of joint 

planning in assessing eligibility for 

customer credits. Taking a more 

expansive view, APPA argues that 

network transmission customers also 

should be able to obtain credits for 

transmission facilities they build 

pursuant to an open and collaborative 

transmission planning process in their 

region or sub-region. This additional 

opportunity for credits, according to 

APPA, would spur participation in the 

transmission planning process and 

would be superior to litigating the 

proper application of the integration 

standard. 

751. Entegra argues that the 

Commission should make the crediting 

policy for network customers consistent 

with the Commission’s policies for 

generator interconnection facilities, and 

require credits to be available for 

facilities that are integrated with the 

transmission grid, without any showing 

of additional benefits and irrespective of 

whether the service in question is 

interconnection service, network 

service, or point-to-point service. 

Entegra further argues that the 

Commission should allow customers to 

sell transmission credits to obtain 

transmission service elsewhere on the 

transmission provider’s system. By 

allowing the development of a more 

liquid market for such credits, Entegra 

reasons, the Commission could increase 

the willingness of market participants to 

fund upgrades to the transmission 

system. 

752. TDU Systems request that the 

Commission recognize that inequities 

have occurred and, if any upgrades are 

required to make network customers’

facilities comparable (or comparably 

integrated), the costs of such network 

upgrades should be rolled into the 

transmission providers’ rates. 

Commission Determination 

753. The Commission declines to 

adopt the credits test for new facilities 

proposed in the NOPR. The intent 

underlying that proposal was to prevent 

application of the integration test in a 

manner that exclusively benefits the 

transmission provider.434 After 

reviewing the comments, we conclude 

that the proposed test may not in fact 

accomplish this objective. The test 

proposed in the NOPR may not 

effectively set forth the relationship of 

the integration standard to the 

comparability requirement. We 

therefore revise the test as follows, to 

more accurately reflect the 

Commission’s intent as expressed in the 

NOPR: A network customer shall 

receive credit for transmission facilities 

added subsequent to the effective date 

of the Final Rule if such facilities are 

integrated into the operations of the 

transmission provider’s facilities; 

provided however, the customer’s 

transmission facilities shall be 

presumed to be integrated if the 

transmission facilities, if owned by the 

transmission provider, would be eligible 

for inclusion in the transmission 

provider’s annual transmission revenue 

requirement as specified in Attachment 

H of the pro forma OATT. 

754. Under our precedent, a 

transmission provider’s facilities are 

presumed to provide benefits to the 

transmission grid, whereas a 

transmission customer must make an 

affirmative showing that its facilities 

provide benefits in order to qualify for 

credits.435 Under the test we adopt in 

this Final Rule, a transmission customer 

will be required to meet the integration 

standard under pro forma OATT section 

30.9 in order to receive a credit for its 

facilities.436 Because joint planning will 

no longer be required in order to obtain 

credits, we find that it is particularly 

important in this context to require a 

showing that a network customer’s 

facilities provide benefits to the 

transmission provider’s grid, i.e., a 

transmission customer should not be 

eligible for credits for facilities that the 

network customer may use to provide 

service for itself but that the 

transmission provider does not need to 

use to provide transmission service to 

any other customer. However, to ensure 

comparability, a presumption of 

integration will be afforded to 

transmission customer facilities if it is 

shown that, if owned by the 

transmission provider, such facilities 

would be eligible for inclusion in the 

transmission provider’s rate base. 

c. Application of the New Test to 

Existing Facilities 

Comments 

755. Several commenters object to the 

Commission’s proposal to apply the 

new comparability test in section 30.9 to 

new facilities, and not to existing 

facilities.437 If the Commission requires 

the same integration standard for both 

existing and new facilities, East Texas 

Cooperatives ask us to specify which 

integration standard—the pre-existing 

integration standard, or the new 

standard that applies the integration 

standard comparably—applies and 

explain the difference and the basis for 

that choice. MDEA, FMPA and TAPS 

argue that no distinction is warranted 

between the treatment of new and 


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438See East Texas Electric Cooperative v. Central 

and South West Services, Inc., 114 FERC ¶ 61,027 

(2006). 

439E.g., Allegheny, EEI, MidAmerican, and 

Nevada Companies. 

440E.g., Allegheny, EEI, Exelon, and 

MidAmerican. 

441See, e.g., City of Westerville, Ohio v. Columbus 

Southern Power Co., 111 FERC ¶ 61,307 (2005). 

existing facilities and that the same 

standard should apply. 

756. TAPS clarifies that it is not 

suggesting that the standard be applied 

retroactively to past uses, but rather 

prospectively to existing facilities, with 

the key consideration being when the 

claim for credits is brought and not 

when the facilities are constructed. 

TAPS argues that it cannot be claimed 

that the revised standard should apply 

only to new facilities because the 

comparability requirement is new. To 

the contrary, TAPS contends that 

comparability has been the theme and 

bedrock foundation of the Commission’s 

transmission open-access requirement 

since its inception. 

757. APPA argues that the 

Commission effectively acknowledges 

in the NOPR that transmission providers 

have failed to plan new facilities jointly 

with their transmission customers for 

the last ten years under the current 

section 30.9, but offers no redress for 

this past discrimination. 

Commission Determination 

758. We conclude that the new test for 

determining credits will apply only to 

transmission facilities added subsequent 

to the effective date of this Final Rule. 

A number of customer-owned 

transmission facilities have been 

developed, and resulting credits 

negotiated and litigated, under the prior 

test which the Commission determined 

to be just and reasonable at the time.438

We find no basis for revisiting the 

Commission’s determinations in those 

cases in this Final Rule. On a 

prospective basis, however, given the 

increased planning and coordination we 

require in the Final Rule, we believe it 

appropriate to apply the new test for 

determining credits. 

d. Cost of Customer Facilities 

Automatically Included in Transmission 

Provider Cost of Service Without a Rate 

Filing 

Comments 

759. Several transmission providers 

argue that, contrary to the Commission’s 

proposal, credits should be added 

automatically to the transmission 

provider’s cost of service.439

760. MidAmerican argues that 

requiring the transmission provider to 

defer including the cost of the 

transmission credit until its next filed 

transmission rate case penalizes the 

transmission provider’s shareholders 

who must unfairly bear the cost of 

providing the credit until the next rate 

case. If the Commission does not allow 

automatic rate recovery of the 

incremental cost of credits, 

MidAmerican continues, the 

Commission should clarify that the 

customer will not be allowed 

transmission facility credits until the 

rate adjustments are filed and accepted 

by the Commission. MidAmerican 

explains that such filings would 

examine only the new revenue 

requirements to be added and should 

not require a general rate case for the 

transmission provider’s entire revenue 

requirement. Nevada Companies 

likewise argues that credits should not 

be granted to network customers if the 

recovery of those credits is not provided 

for in the revenue requirement. 

761. TAPS agrees with the 

Commission’s conclusion that it would 

not be appropriate in this rulemaking to 

allow transmission providers to 

automatically add costs of credits to 

their cost of service, and that such costs 

should continue to be evaluated as part 

of a regular transmission rate case (or 

recovered through an approved formula 

rate). APPA expresses concern that 

transmission providers may attempt to 

use the Commission’s decision not to 

allow them to add the costs of credits 

associated with customer-owned 

transmission facilities automatically to 

their costs of service as a pretext for not 

granting such credits in the first 

instance (at least until they decide to 

file a new rate case). APPA continues 

that a transmission provider’s decision 

not to exercise the option to file under 

FPA section 205 a new rate case or an 

automatic adjustment clause should not 

serve as a reason to allow it to decline 

to provide credits. 

762. EEI explains that the customary 

basis for not allowing single-issue rate 

adjustments for new transmission 

facilities is that while one aspect of the 

transmission provider’s costs may have 

increased, others may have decreased or 

load may have increased. This is not the 

case with respect to the inclusion of the 

transmission costs related to customerowned facilities, EEI continues, since 

the existence of customer-owned 

facilities does not have any impact on 

the transmission provider’s own cost of 

service. EEI concludes that a 

transmission provider should not be 

forced into what is essentially rejustifying its transmission cost of service 

simply because a customer receives a 

credit for the integration of its own 

facilities. 

763. Some commenters also address 

the option currently open to 

transmission providers to add an 

automatic adjustment clause to their 

rates through a rate filing with the 

Commission.440 EEI argues that if the 

concept of an automatic adjustment 

clause is just and reasonable for one 

transmission provider, it is equally just 

and reasonable for all transmission 

providers, and there is no need to adopt 

a case-by-case approach. EEI further 

requests that the Commission clarify 

that its policy is to accept rate 

adjustments that incorporate the costs 

that transmission providers incur to 

provide credits related to customerowned facilities, provided that the rate 

adjustment methodology is just and 

reasonable. MidAmerican contends that 

the revenue requirement of the 

transmission provider and those of 

transmission customers should not be 

co-mingled, rather, consistent with 

Commission precedent, the burden is on 

the transmission-owning customer to 

demonstrate to the Commission that its 

cost of service and revenue requirement 

used to establish the amount of the 

credit are just and reasonable before it 

can receive credits. As for 

nonjurisdictional entities, MidAmerican 

explains that they may file for a 

declaratory ruling from the Commission 

regarding their revenue requirement. 

764. Allegheny argues that if the 

Commission continues to deny 

transmission providers an automatic 

adjustment clause for these credits, it 

should, at a minimum, assure 

transmission providers that 

transmission credits will be recognized 

as a cost of service in FPA section 205 

rate proceedings. 

765. Entergy argues that the 

Commission should recognize that any 

filed agreement providing for payments 

of credits would be subject to the filedrate doctrine. 

Commission Determination 

766. We are not persuaded to 

generically allow automatic recovery of 

the costs of credits associated with 

integrated transmission facilities to the 

transmission provider’s cost of service. 

These costs typically are considered and 

evaluated as part of a regular cost of 

service review process. Automatic 

recovery of the costs of credits would be 

contrary to our long-standing policy 

concerning single-issue rate 

adjustments, a policy we decline to 

modify here.441 Nevertheless, 

transmission providers continue to have 

the option to propose an automatic 

adjustment clause in their rates under 


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442E.g., APPA, Bonneville, EEI, Exelon, 

FirstEnergy, Nevada Companies, and TAPS. 

443E.g., FirstEnergy, Seattle, and Suez Energy NA. 

444Citing Nevada Power Co., 101 FERC ¶ 61,036 

at P 8 (2002). 

445Order No. 888 at 31,742; Order No. 888-A at 

30,271. 

446E.g., Indicated New York Transmission 

Owners, ISO New England, PJM, and SPP. 

447For example, NYISO’s tariff provides that a 

facilities study will contain a non-binding estimate 

as to the feasible Transmission Congestion 

Contracts (TCCs) resulting from the construction of 

new facilities. There, upon completion of the 

transmission upgrade and the first subsequent 

centralized TCC auction, the NYISO will determine 

the incremental TCCs associated with the upgrade. 

See section 19.4 ‘‘Facilities Study Procedures’’ of 

NYISO’s tariff. Similarly, PJM’s tariff provides that 

an interconnection customer that undertakes 

responsibility for constructing or completing 

network upgrades and/or local upgrades to 

accommodate its interconnection request will be 

entitled to receive the incremental Auction Revenue 

Rights associated with such facilities and upgrades 

subject to conditions. See section 46.1 ‘‘Right of 

Interconnection Customer to Incremental Auction 

Revenue Rights’’ of PJM’s tariff. 

FPA section 205 to address the time lag 

between incurring costs associated with 

credits and the transmission provider’s 

next rate case. 

767. Contrary to EEI’s assertions, 

customer credits do not warrant an 

exception to the Commission’s general 

policy regarding single-issue rate 

adjustments. EEI argues that customer 

credits should be treated differently 

because the existence of customer 

owned facilities, in EEI’s view, does not 

have any impact on the transmission 

providers’ own cost of service. Even if 

true, this fact would not obviate the 

Commission’s policy. Regardless of 

whether the customer credit is deemed 

to impact the transmission provider’s 

own cost of service, the costs it imposes 

may be offset by cost decreases in other 

areas, by load growth, or both. Allowing 

single-issue rate adjustments would 

enable a utility to increase the total rate 

charged by focusing solely on a single 

cost element, while avoiding scrutiny of 

all other determinants of the rate. The 

Commission has an obligation to ensure 

the justness and reasonableness of the 

total rate and it would be improper to 

allow a utility to raise rates by 

selectively focusing only on particular 

elements of its costs, while avoiding 

scrutiny of other rate inputs. The 

Commission has refused to allow such 

rate treatment except in the most 

limited of circumstances and we find no 

basis for deviating from that policy in 

this context. As explained above, a 

transmission provider that wishes to 

add an automatic adjustment clause to 

its rates may seek Commission approval 

for its methodology in a filing submitted 

under FPA section 205. 

e. Point-to-Point Customers Not Eligible 

for Credits on Generic Basis 

Comments 

768. Several commenters support the 

Commission proposal to not make 

credits generically available to point-topoint customers that own transmission 

facilities.442 APPA argues that if the 

frequency of cases seeking credits for 

facilities owned by point-to-point 

customers is high, then the Commission 

should reconsider its decision to use a 

case-by-case approach. 

769. Some commenters encourage the 

Commission to clarify that point-topoint transmission customers that pay 

for upgrades should be compensated if 

such upgrades benefit the system.443

PGP argues that customers be given 

credits if they meet the same conditions 

as network customers who would 

qualify. Additionally, Entegra contends 

that denying credits for upgrades 

funded by point-to-point customers 

would overlook the Commission’s past 

warnings that a customer funding any 

new facilities integrated with the grid 

should be entitled to credits because a 

transmission system ‘‘cannot be 

dismembered’’ or examined 

piecemeal.444

Commission Determination 

770. The Commission adopts the 

NOPR proposal not to make credits 

generically available for point-to-point 

customers that own transmission 

facilities. As the Commission explained 

in the NOPR, a network customer takes 

a usage-based service which integrates 

its resources and loads and pays on the 

basis of its total load on an ongoing 

basis. The transmission provider 

includes the network customer’s 

resources and loads in its long-term 

planning horizon and the two parties 

coordinate operations of their facilities 

through a network operating agreement. 

In this way, network service is 

comparable to the service that the 

transmission provider uses to serve its 

own retail native load, and credits for 

certain integrated network facilities are 

appropriate. The point-to-point 

customer, however, does not purchase 

integration service, nor does it sign a 

network operating agreement with the 

transmission provider. Because of the 

inherent differences between point-topoint and network service, we therefore 

decline to require that transmission 

providers make credits generically 

available to point-to-point customers 

that own transmission facilities. If a 

particular facility owned by a point-topoint customer meets all the criteria for 

credits, we will continue to address 

such situations on a fact-specific, caseby-case basis consistent with the 

Commission’s statement in Order No. 

888.445

f. RTO and ISO Issues 

Comments 

771. Several RTOs or ISOs assert that 

they should not be required to comply 

with the crediting provisions because 

their respective planning processes and 

procedures are superior to or obviate the 

need for those set forth in the NOPR.446

CAISO states that it does not oppose the 

Commission’s proposal, provided that 

the Commission confirms that facilities 

cannot be integrated into CAISO’s 

operations unless they are under 

CAISO’s operational control, consistent 

with the Commission’s prior rulings. 

772. In Xcel’s view, an RTO has no 

incentive to refuse to jointly plan to 

avoid paying a credit and there is thus 

good cause to allow an RTO to deviate 

from the language in the pro forma 

OATT relating to joint planning of new 

facilities in order to be considered for a 

facility credit. Xcel and International 

Transmission argue that RTOs should be 

allowed to incorporate network 

customer-owned facilities into RTO 

rates in the same manner as if they were 

constructed by a transmission owner, 

while ensuring against double recovery 

of both revenue requirements and 

network credits. 

Commission Determination 

773. The Commission concludes that 

it would not be appropriate at this time 

to generically exempt all ISOs and RTOs 

from the Final Rule requirements 

regarding credits for network 

transmission customers. We will 

address issues relating to network 

transmission customers credits in the 

RTO and ISO context in orders 

addressing OATT reform compliance 

filings submitted by each RTO and ISO. 

The Commission determined previously 

that the existing tariffs of certain RTOs 

and ISOs provide opportunities for 

transmission customers to receive credit 

or the equivalent (e.g., Transmission 

Congestion Contracts, Firm 

Transmission Rights or Auction 

Revenue Rights) for building facilities or 

upgrades that are consistent with or 

superior to Order No. 888 

requirements.447 Each RTO and ISO will 

have the opportunity to show on 

compliance that this continues to be the 

case given the reforms adopted in this 

Final Rule. 


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448East Texas Electric Cooperative, Inc. v. Central 

and Southwest Services, Inc., 108 FERC ¶ 61,077 at 

P 21–23 (2004), reh’g denied, 114 FERC ¶ 61,027 

at P 43–44 (2006), appeal docketed, No. 06–1090 

(D.C. Cir. Mar. 10, 2006) 

449Promoting Transmission Investment through 

Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 

31, 2006), FERC Stats. & Regs. ¶ 31,222 (2006), order 

on reh’g, Order No. 679–A, 72 FR 1152 (Jan. 10, 

2007), FERC Stats. & Regs. ¶ 31,236 (2007). 

450See Order No. 888 at 31,696; pro forma OATT 

section 23.1. 

451 Id. at 31,740. 

452Order No. 888–A at 30,224. 

453The existing OASIS posting requirements for 

reassigned capacity already require, if selling on 

OASIS, for sellers to include data elements such as 

the path name, point of receipt, point of delivery, 

source, sink, capacity requested, capacity granted, 

start time, stop time, and offer price. See 18 CFR 

37.6(c)(5). 

Other issues 

Comments 

774. East Texas Cooperatives argue 

that the Commission should clarify that 

a network customer is entitled to 

transmission credits for its own 

transmission facilities and the facilities 

of member utilities for which the 

network customer arranges and pays for 

network transmission services. East 

Texas Cooperatives explain that a recent 

Commission decision 448 allows 

transmission credits only for facilities 

owned by the generation and 

transmission cooperative (G&T) and not 

for its individual members, which in its 

view is contrary to past Commission 

precedent. 

775. FMPA asks that the Commission 

affirmatively state that it will exercise 

its jurisdiction to ensure that public 

power entities are compensated for 

transmission investment (including 

joint transmission projects) in the event 

of dispute with jurisdictional 

transmission providers. FMPA explains 

that the proposed revisions to section 

30.9 may be insufficient to address all 

problems that may arise, especially in 

regions without an RTO or an existing 

compensation method. NRECA asks the 

Commission to prohibit RTOs and ISOs 

from using a non-public utility’s 

transmission facilities without 

compensating the entity simply because 

it has not joined the RTO or ISO. 

NRECA argues that comparable 

treatment requires compensation for use 

of a transmission owner’s facilities, 

whether the owner is subject to 

Commission jurisdiction or not, and the 

Commission should not consider a 

transmission tariff to be just and 

reasonable if it allows unlawful trespass 

and conversion. 

776. TAPS asks the Commission to 

include language in section 30.9 of the 

pro forma OATT that affirmatively 

states customers’ eligibility for rate 

incentives for new facilities under 

recently established Commission policy. 

TAPS further requests that the 

Commission guard against a 

transmission provider blocking such 

incentive based credits by refusing to 

engage in joint development of 

transmission projects with its 

customers. 

Commission Determination 

777. The Commission finds that there 

is not enough evidence on the record to 

make a generic determination on these 

issues and, instead, will address them 

on a case-by-case basis in response to 

appropriate filings under FPA sections 

205 and 206. With regard to incentives 

for new facilities, the Commission has 

already addressed incentives for 

transmission infrastructure investment 

in Order No. 679.449 There the 

Commission identified specific 

incentives that it will allow when 

justified in the context of individual 

proceedings. With regard to FMPA’s 

concerns regarding potential disputes 

over compensation for transmission 

investment by non-public utilities, we 

note that section 12 of the existing pro 

forma OATT contains dispute 

resolution procedures. This Final Rule 

also requires transmission providers to 

propose a dispute resolution process as 

part of the coordinated planning 

process. Additionally, the Commission’s 

Dispute Resolution Service is available 

to assist in developing a dispute 

resolution process, as well as the 

Commission via a formal complaint 

filed pursuant to section 206 of the FPA. 

4. Capacity Reassignment 

778. In Order No. 888, the 

Commission concluded that a 

transmission provider’s pro forma 

OATT must explicitly permit the 

voluntary reassignment of all or part of 

a holder’s firm point-to-point capacity 

rights to any eligible customer.450 With 

respect to the rate for capacity 

reassignment, the Commission 

concluded it could not permit 

reassignments at market-based rates 

because it was unable to determine that 

the market for reassigned capacity was 

sufficiently competitive so that 

assignors would not be able to exert 

market power. Instead, the Commission 

capped the rate at the highest of (1) The 

original transmission rate charged to the 

purchaser (assignor), (2) the 

transmission provider’s maximum 

stated firm transmission rate in effect at 

the time of the reassignment, or (3) the 

assignor’s own opportunity costs 

capped at the cost of expansion (price 

cap). The Commission further explained 

that opportunity cost pricing had been 

permitted at ‘‘the higher of embedded 

costs or legitimate and verifiable 

opportunity costs, but not the sum of 

the two (i.e., ‘or’ pricing is permitted; 

‘and’ pricing is not).’’ 451 In Order No. 

888–A, the Commission explained that 

opportunity costs for capacity 

reassigned by a customer should be 

measured in a manner analogous to that 

used to measure the transmission 

provider’s opportunity cost.452

NOPR Proposal 

779. In the NOPR, the Commission 

noted that capacity reassignment does 

not appear to have developed into a 

competitive alternative to primary 

capacity since the issuance of Order No. 

888. To facilitate development of this 

market, the Commission proposed to 

remove the price cap on capacity 

reassignment and allow negotiated rates 

for transmission capacity reassigned by 

transmission customers. The 

Commission explained that, because the 

price cap appears to have reduced 

customers’ transmission options, 

removal of the cap may be warranted 

without a market-by-market analysis. 

Due to market power concerns, 

however, the Commission proposed to 

retain the price cap for capacity 

reassigned by the transmission 

provider’s merchant function or its 

affiliates. 

780. The Commission proposed to 

monitor the market for reassigned 

capacity by requiring regular OASIS 

postings and quarterly reports from 

transmission providers using 

information submitted by reassigning 

customers. First, the Commission 

proposed retaining the existing posting 

and filing requirements for reassigned 

capacity transactions to ensure that 

capacity is equally available to all 

customers and to protect against undue 

discrimination and the potential 

exercise of market power.453 Second, 

the Commission asked several questions 

regarding OASIS postings and the data 

that should be required in quarterly 

reports related to capacity 

reassignments: (1) What information 

should be required in the quarterly 

reports and OASIS postings, i.e., 

information about the capacity released, 

the original rate paid for that capacity, 

the price charged to the assignee for the 

capacity, and the term of the 

assignment; (2) whether other 

information was necessary for 

operational and reliability purposes; (3) 

whether additional reports by assignors 

to the transmission provider are 

necessary and, if so, what information 

should be reported by assignors; (4) 


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454E.g., Allegheny, AWEA, Constellation, EEI, 

Entegra, EPSA, Exelon, Morgan Stanley, PPL, 

Seattle, Suez Energy NA, and TranServ. 455Citing Natural Gas Pipeline Negotiated Rate 

Policies and Practices, 114 FERC ¶ 61,034 (2006) 

(Brownell, Comm’r concurring). 

456E.g., APPA, AWEA, NRECA, Seattle, TAPS, 

and TDU Systems. 

457Citing Public Service Electric & Gas Company, 

78 FERC ¶ 61,119 at 61,455 (1997) (granting marketbased rate authority based in part on the adequate 

‘‘mitigation of market power’’ as evidenced by a pro 

forma OATT). 

458E.g., Community Power Alliance, EEI, Entergy, 

FirstEnergy, Imperial, Manitoba Hydro, 

MidAmerican, Progress Energy, and Salt River. 

459E.g., MidAmerican, PNM–TNMP and South 

Carolina E&G. 

460E.g., EEI, Entergy, MidAmerican, PNM–TNMP, 

Progress Energy, Southern, and South Carolina 

E&G. 

461E.g., Community Power Alliance, Entergy, 

Imperial, Manitoba Hydro, Salt River, South 

Carolina E&G, and Southern. 

462E.g., EEI, Entergy, MidAmerican, and Progress 

Energy. 

463See Order No. 888 at 31,697. 

464E.g., EEI, MidAmerican, and Progress Energy. 

should the Commission establish a new 

quarterly reporting process with a new 

form, or use the existing Electric 

Quarterly Report procedures; and (5) 

how frequently should OASIS postings 

be made. 

Comments 

Lifting the Price Cap for All 

Transmission Customers 

781. Some commenters support 

eliminating the price cap for 

reassignment of transmission capacity 

in the secondary market.454 For 

example, EPSA states that the 

Commission is correct to recognize that 

negotiated rates are dynamic and 

provide a market discipline on the price 

for reassigned capacity. Entegra argues 

that the Commission’s removal of rate 

caps on releases of natural gas pipeline 

capacity increased available peak 

capacity and facilitated the movement 

of capacity into the hands of those that 

value it most highly, proving that an 

uncapped capacity release market can 

be both competitive and result in just 

and reasonable rates for customers.455

Exelon supports eliminating the price 

cap, but asserts that, since the 

transmission customer is seeking to 

reassign the capacity, it is likely the 

capacity is not useful in gaining access 

to load and therefore is not very 

valuable. BP Energy contends that 

transparent competition between the 

transmission provider (marketing 

primary and subscribed but unutilized 

capacity) and transmission customers, 

with monitoring by the Commission and 

prospective capacity purchasers, will 

moderate if not eliminate the potential 

exercise of market power and encourage 

the release of capacity that is not 

otherwise used or useful. As a result, BP 

Energy urges the Commission to require 

transmission providers to facilitate a 

competitive capacity reassignment 

process, similar to that used for capacity 

release on natural gas pipelines. 

782. Some commenters support the 

proposal to retain the price cap for 

transmission providers and their 

affiliates.456 Seattle states that the 

Commission is correct to continue to 

cap prices for the transmission provider 

since the transmission provider is a 

regulated monopoly. In its reply, 

Entegra states that the Commission has 

found that having a pro forma OATT 

mitigates but does not eliminate a 

transmission provider’s ability to 

leverage its monopoly power in 

transmission into market power in 

generation markets.457 Entegra further 

contends that Southern, Entergy, and 

other transmission providers have 

monopoly power in transmission 

markets in their service territories and 

without a cap would exploit that market 

power in the secondary market. 

Moreover, Entegra argues that allowing 

transmission providers and their 

affiliates to charge market-based rates 

for transmission capacity in the primary 

or secondary market would exacerbate 

the skewed incentives that already 

operate to discourage construction of 

much needed transmission facilities in 

many markets. 

783. Many commenters contend that 

lifting the price cap for reassignment of 

transmission capacity only for 

unaffiliated transmission customers 

would be unreasonable.458 For example, 

Entergy argues that for the wholesale 

markets to work all wholesale market 

participants, including the transmission 

provider’s affiliated marketers, must be 

treated comparably under the pro forma 

OATT. EEI contends that lifting the 

price cap can result in a more robust 

secondary market for transmission 

capacity and will reduce any risks that 

transmission customers may associate 

with being required to purchase 

transmission service for five-year terms 

in order to obtain rollover-rights. In 

addition, Manitoba Hydro asserts that 

changing the current one-year minimum 

term creates additional risks for 

transmission customers and therefore 

having the ability to re-sell the 

transmission capacity at market-based 

rates would assist transmission 

customers to better manage the financial 

risks involved with holding longer term 

contracts. 

784. Some commenters support lifting 

the price cap for affiliates if caps are 

removed for non-affiliates, but are only 

generally supportive of lifting the price 

cap.459 If the Commission does lift the 

price cap, Southern argues that it should 

also lift the price caps for the 

transmission provider and its affiliates 

as well in order to counter efforts to 

corner the market and other related 

unforeseen consequences. MidAmerican 

agrees, asking the Commission to retain 

the cap for all transmission customers if 

the transmission provider and its 

affiliates are not allowed to resell 

capacity at market-based rates. 

785. Several commenters argue that 

the Commission’s justification for 

eliminating the price cap—namely, 

reducing the ability of non-affiliated 

customers to exercise market power in 

the secondary market through 

competition among releasing customers, 

monitoring the market via quarterly 

reports, and continuing rate regulation 

of primary capacity—applies to energy 

and marketing affiliates as well.460 First, 

several commenters argue that the 

Standards of Conduct and existing pro 

forma OATT rules ensure that 

transmission provider affiliates have no 

more ability to obtain information about 

the transmission system or to reserve 

point-to-point transmission capacity 

than unaffiliated customers. 461

Entergy contends that, although the 

Commission correctly concludes 

elsewhere in the NOPR that functional 

unbundling and Standards of Conduct 

requirements, if properly enforced are 

sufficient to address affiliate abuse 

concerns, the Commission seems to 

assume that those same protections 

cannot be effective where the 

reassignment of transmission capacity is 

concerned. 

786. Second, some commenters 

question the Commission’s assertion 

that permitting transmission provider’s 

energy and marketing affiliates to resell 

or reassign transmission capacity would 

give them the ability to favor their own 

generation.462 For example, EEI 

contends that transmission providers 

have no control over the reassignment 

process, and transmission customers 

have complete freedom to reassign 

transmission capacity to any customer 

they choose. Entergy points out that 

under Order No. 888 the assignor of 

capacity may deal directly with an 

assignee and without involvement of the 

transmission provider.463

787. Third, some commenters 

disagree with the Commission’s 

statement that lifting the price cap for 

affiliates may dampen transmission 

investment.464 These same commenters 

argue that there is no relationship 

between the transmission provider’s 

obligation to build transmission 


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465E.g., EEI, Entergy and MidAmerican. 

466E.g., Entegra and NorthWestern. 

467E.g., Community Power Alliance, EEI, 

FirstEnergy, Imperial, Northwest IOUs, Southern, 

and TVA. 

468E.g., Alcoa, APPA, International Transmission, 

Nevada Companies, NRECA, PJM, Public Power 

Council, TAPS, and WAPA. 

469E.g., APPA, Nevada Companies, Northwest 

IOUs, NRECA, PJM, TAPS, and WAPA. 

facilities to accommodate third party 

requests for transmission service and 

the ability of marketing and energy 

affiliates to resell unused transmission 

capacity at market-based rates. For 

example, Progress Energy and others 

contend that the transmission provider 

is obligated under the pro forma OATT 

to construct transmission facilities to 

meet all requests for transmission 

service.465 Progress Energy and EEI 

contend that the transmission customer 

will decide to purchase secondary 

market transmission capacity if it meets 

the reasonable needs of customers so 

long as the capacity is priced below the 

higher of the embedded cost of 

transmission service or the cost of 

expansion. EEI argues that the customer 

can require the transmission provider to 

construct additional capacity to 

accommodate the customer’s request for 

service if secondary market service—

whether offered by the transmission 

provider’s marketing and energy 

affiliates or by a third party customer—

is priced above the cost of expansion. In 

such situations, EEI and Progress Energy 

contend that the cost of expansion 

serves as a cap on the price at which 

both third party customers and the 

transmission provider’s marketing and 

energy affiliates can resell transmission 

capacity. Moreover, Entergy argues that 

this is the same justification that the 

Commission relies upon to conclude 

that transmission customers would not 

hoard secondary capacity, and it is 

arbitrary for the Commission to ignore 

that principle in concluding that a 

transmission provider would hoard 

capacity. 

788. Additionally, some commenters 

argue that lifting the price cap for 

affiliates will encourage transmission 

investment.466 NorthWestern contends 

that allowing transmission providers to 

collect more than their ceiling price 

when the market is willing to pay a 

higher price could further the 

Commission’s goal of encouraging 

transmission investment to maintain 

reliability and keep pace with load 

growth. NorthWestern suggests that the 

Commission could place restrictions on 

the proceeds in excess of the ceiling 

price such that, within some specified 

period, the dollars must be reinvested 

into transmission facilities or be 

refunded back to customers. 

789. Several commenters contend that 

lifting the price cap only for nonaffiliates could dampen participation in 

the secondary market and place 

affiliates at a competitive 

disadvantage.467 Community Power 

Alliance argues it is unfair for the 

Commission to now say that their 

separated marketing affiliates, which 

have abided by Commission rules like 

any other market participant, cannot 

now compete on an equal footing with 

other participants in the secondary 

market for transmission capacity. Rather 

than prohibit transmission providers’

affiliates from reselling capacity, 

Manitoba Hydro suggests that a more 

equitable approach would be for the 

Commission to lift the price cap for all 

resold transmission capacity, except for 

transmission capacity administered by 

an affiliate’s transmission provider. 

790. To the extent the Commission 

adopts the proposed restriction on 

affiliate reassignments, MidAmerican 

seeks guidance on whether the 

transmission provider is expected to 

assure that the assignee is a valid 

eligible customer under the pro forma 

OATT. Similarly, Southern encourages 

the Commission to carefully identify 

and evaluate the possible adverse effects 

of lifting any reassignment price caps. 

Southern asserts that such effects could 

include expanded involvement and 

influence by financial players driven 

exclusively by profit motives and who 

may not be subject to Commission 

regulation. 

791. Several commenters contend that 

the Commission should retain the price 

cap for the reassignment of transmission 

capacity for all customers, not just 

affiliates of the transmission 

provider.468 APPA argues that allowing 

the resale of such a scarce and valuable 

service to those who value the capacity 

more highly is a recipe for undue 

discrimination and unjust and 

unreasonable transmission rates, at the 

expense of end-use customers. While 

NRECA opposes the Commission 

proposal to remove the price cap, 

NRECA would support the proposal to 

retain the price caps for affiliates. 

Similarly, TAPS supports the decision 

not to lift the price caps for affiliates; 

however, TAPS urges the Commission 

to rethink the NOPR’s proposal to 

otherwise lift the price cap for nonaffiliates. 

792. Several commenters argue that 

lifting the cap for any transmission 

customers would encourage the exercise 

of market power, including hoarding, 

and discourage transmission 

investment.469 If removal of the cap 

were effective in making reassignment 

more profitable, TAPS contends it 

would encourage hoarding of capacity 

on key paths that would run afoul of the 

directive in FPA section 217(b)(4) to 

ensure the ability of LSEs to secure 

long-term rights for their long-term 

power supply arrangements. Northwest 

IOUs argue that lifting the price cap 

would encourage non-affiliated 

transmission customers to buy 

transmission capacity at cost and resell 

it at market, in an effort to reduce the 

amount of transmission capacity 

available for resource development and 

other long-term uses. PJM argues that 

the final rule should include a 

requirement that appropriate hoarding 

mitigation procedures be implemented 

should the price cap be removed. APPA 

argues that, if no transmission capacity 

is available in the short run from the 

transmission provider, and an LSE 

needs additional capacity to serve load 

within the next day or week, the fact 

that the transmission provider could 

build capacity in future years at an 

incremental rate has little if any bearing 

on the price that LSE is willing to pay 

for the next day, week, or month to avert 

a looming supply problem. TVA asserts 

that transportation prices rose 

drastically during periods of high 

demand or constraint after the price cap 

for resale of gas transmission capacity 

was removed in Order No. 637 for 

everyone except pipelines and their 

affiliates. TVA states that this benefited 

entities that could afford to hold 

capacity, but harmed those that had to 

buy additional capacity on a short-term 

basis. 

793. Alcoa and Nevada Companies 

argue that there is a significant potential 

for abuse in connection with the 

removal of the cap, particularly in load 

pockets. Alcoa argues that it is not clear 

at this point that there are sufficient 

safeguards in place to prevent and 

monitor the exercise of market power, 

something that must be assured before 

the cap is lifted on transmission 

capacity resale. Nevada Companies 

contend the proposal to remove the cap 

may actually reduce utilization of the 

grid, contrary to its intended purpose. 

For example, Nevada Companies state 

that transmission customers who have 

locked up capacity in constrained 

markets will likely wait to the very last 

minute to make that capacity available 

in order to drive up the price, which 

will often result in the capacity not 

being utilized if transactions cannot 

occur quickly enough. Some 


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470E.g., APPA, International Transmission, 

NRECA, Public Power Council, and Seattle. 

471E.g., Alcoa, APPA, Bonneville, TAPS, and 

WAPA. 

472Citing Farmers Union Cent. Exch., Inc. v. 

FERC, 734 F.2d 1486, 1508–10 (D.C. Cir. 1984) 

(concluding that ‘‘undocumented reliance on 

market forces is insufficient to satisfy the 

Commission’s regulatory responsibilities.’’); 

California ex. Rel. Lockyer v. FERC, 383 F.3d 1006, 

1013 (9th Cir. 2004). 

473E.g., BP Energy, Seattle, and TranServ. 

474E.g., Ameren, Constellation, SPP, and 

TranServ. ISO New England and PJM argue that, as 

providers of transmission service, they have no 

affiliates and likewise are not bound by the 

Commission’s reassignment proposal. 475E.g., Alcoa, APPA, Manitoba Hydro, PGP, 

Sacramento, and Seattle. 

commenters contend that, like LMP in 

organized markets, allowing price 

signals via lifting the cap may not 

encourage transmission investment, but 

rather create entrenched interests that 

profit from the existence of congestion 

and oppose efforts to eliminate such 

congestion through transmission 

expansion.470 If transmission providers 

are forced to purchase capacity at higher 

prices on the secondary market, 

Imperial argues that their native load 

customers be harmed by such higher 

prices, which may in turn hamper 

transmission expansion contrary to the 

Commission’s stated goals for promoting 

transmission investment. 

794. In addition, some commenters 

are skeptical of the Commission’s 

assertion that existing market 

mechanisms are a sufficient deterrent to 

anticompetitive behavior.471 WAPA and 

TAPS argue that, while eliminating the 

price cap might increase customers’

transmission options, the Commission 

still needs to conduct case-by-case 

market power analyses prior to lifting 

the cap.472 As a result, WAPA argues, it 

is critical for the Commission to identify 

and aggressively mitigate all 

transmission market power on an ex 

ante basis, rather than utilizing an ex 

post monitoring scheme as proposed in 

the NOPR. If the Commission lifts the 

price cap, certain commenters argue that 

the Commission should establish 

competitive bidding transaction 

standards.473 For example, Seattle 

asserts that a standards organization 

such as NAESB will need to establish 

bid/ask transaction standards and 

reporting formats and the Commission 

must periodically validate the 

assumption that the secondary market is 

workably competitive. 

Application of the Price Cap to 

Members of ISOs/RTOs 

795. Some commenters request 

clarification that, if the Commission 

retains the price cap for capacity 

reassigned by affiliates, that it not apply 

to entities that have turned over control 

and operation of their transmission 

facilities to an RTO, ISO or independent 

entities.474 For example, Constellation 

requests that the Commission clarify 

that the revised pro forma OATT does 

not impose the cap on affiliates of 

transmission owners that have turned 

their transmission facilities over to an 

RTO/ISO when they reassign 

transmission capacity on facilities 

operated by the RTO/ISO. While MISO 

takes no position on whether the 

Commission should retain its cap for 

stand-alone transmission providers and 

their affiliated customers, it argues that 

the cap makes no sense in the context 

of capacity reassignments administered 

by RTOs and ISOs. MISO observes that 

the NOPR cites affiliate preference and 

market power concerns as the basis for 

retaining the cap on reassignments by 

transmission providers and their 

affiliated customers, which MISO argues 

are not applicable in the RTO/ISO 

context. Further, MISO argues that the 

ownership of transmission assets in an 

RTO/ISO is divorced from the provision 

of transmission service, and RTO 

transmission owners are transmission 

customers no different from any other 

customer class. 

796. On the contrary, APPA notes that 

the issue is whether the transmission 

customer holding transmission rights 

over a constrained path has the ability 

to exercise market power and charge 

unjust and unreasonable rates if the cap 

is lifted. APPA argues that the issue is 

the same in both RTO and non-RTO 

regions. In APPA’s view, whether the 

public utility transmission provider has 

joined an RTO, does not affect the 

ability of its merchant affiliate to extract 

unjust and reasonable rents for the 

resale of scarce transmission rights. 

Alternative Price Cap Proposals 

797. Some commenters propose 

alternatives to negotiated pricing of 

transmission capacity in the secondary 

market.475 While APPA supports 

retaining the current rate cap, it 

contends that firm point-to-point 

customers should be allowed to collect 

demonstrable out-of-pocket costs in 

addition to the maximum capped rate. 

Alcoa suggests that the Commission 

could stimulate the secondary market 

for transmission capacity by increasing 

the cap and allowing parties to charge 

a percentage over the original price 

paid. Seattle contends that the existing 

Commission policy could be 

incrementally modified to permit 

recovery of remarketing costs and 

recognize that, for many customers, the 

transmission right is held at a much 

higher per unit cost than the primary 

rate stated in the transmission 

provider’s pro forma OATT (due in part 

to the fact that a customer may not use 

all of the capacity for which it has 

contracted). 

798. Sacramento proposes that prices 

for released capacity be capped at the 

amortized and rate-based cost of a 

transmission upgrade. Seattle states that 

costly redirect processes, including 

system impact studies, may be needed 

to create a reassignment product that 

has value to other customers, given that 

the point of receipt, point of delivery or 

both typically change in a reassignment. 

While the current pro forma OATT 

pricing model differentiates 

transmission rates based on term and 

time of day (monthly, weekly, daily, 

hourly), Seattle asserts that seasonal 

variations in the value of transmission 

rights offered for short-term 

reassignment are also worthy of 

consideration, especially in a region like 

the Northwest, where power production 

varies seasonally. 

799. MISO states that it believes the 

Commission should further strengthen 

its pro-competitive policy by permitting 

RTO/ISO transmission providers to offer 

firm point-to-point transmission service 

for drive-out/drive-through transactions 

at market-based rates, including 

‘‘rollover’’ transactions. MISO states that 

the principles for allocating firm 

capacity on such interfaces should be 

the same as for reassigning capacity 

within an RTO: i.e., permitting 

customers that value the capacity more 

highly to benefit from it. MISO asserts 

that allowing market participants to 

compete based strictly on price on 

external interfaces would resolve many 

inefficiencies stemming from the 

cumbersome queue administration 

procedures currently used on such 

facilities. MISO states that the final rule 

should encourage RTOs and ISOs to 

introduce such competitive practices in 

their footprints. 

800. PGP proposes two alternative 

approaches. First, PGP proposes that the 

Commission could wait until a regional 

approach for pricing reassignments is 

developed in those areas of the country 

that still rely on reassignments of pointto-point capacity to create a secondary 

market in transmission service. Second, 

PGP proposes that any decision to 

remove the price cap could be made on 

a case-by-case basis after a filing by a 

point-to-point customer at the 

Commission, in which the applicant 

must meet standards developed by the 

Commission that demonstrate the lack 

of market power in relevant 

transmission or generator markets. 


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476E.g., Bonneville, FirstEnergy, and PJM. 

477E.g., EEI, Entergy, Nevada Companies, PNM–

TNMP, South Carolina E&G, Southern, and TVA. 

478E.g., EEI, PJM, and Seattle. 

479E.g., PJM, PNM–TNMP, and TranServ. 

480E.g., Allegheny, Morgan Stanley, NAESB, 

Seattle, and TranServ. 

481E.g., Powerex, Sacramento, TAPS, and 

Williams. 

482E.g., APPA, Powerex, and SPP. 

801. South Carolina E&G requests that 

the Commission clarify how the cap is 

calculated if the Commission chooses to 

retain the price cap. International 

Transmission asserts that the 

Commission should lift the price cap, 

on an experimental basis, similar to the 

approach followed in the natural gas 

industry. Similarly, WAPA recommends 

that the Commission either retain the 

price cap or institute a separate 

rulemaking proceeding for the purpose 

of establishing detailed market analysis 

criteria for eliminating the price cap for 

specific transmission segments or paths. 

Posting and Filing Requirements 

802. Some commenters support the 

proposal to require transmission 

providers to submit quarterly reports 

and make OASIS postings regarding 

reassignments of transmission 

capacity.476 Bonneville asserts that, at a 

minimum, transmission customers 

should be required to provide a 

downloadable file to the transmission 

provider for posting on the transmission 

provider’s OASIS that identifies the 

assignee, the amount of capacity 

assigned or transferred, the date of the 

offer of assignment, and the rate and 

duration of the assignment. Other 

commenters argue that transmission 

customers should be given greater 

reporting responsibility.477 Southern 

contends that transmission providers 

should not be burdened with submitting 

quarterly reports and making OASIS 

postings based on assignment 

information provided to them by other 

assignors/assignees. Rather, Southern 

and EEI argue that assignment 

information should be filed by the 

respective assignors and assignees in 

connection with their Electric Quarterly 

Report filings and not by the 

transmission provider. PNM–TNMP 

contend that the Commission should 

prescribe specific reporting obligations 

and associated deadlines to the 

assignors and reporting obligations 

should also include appropriate 

consequences for non-compliance on 

the part of the assignor. Nevada 

Companies ask that a system be put in 

place to charge relevant transmission 

customers for the additional reporting if 

the transmission provider is required to 

do the reporting, either on the OASIS or 

through some other mechanism. 

803. Some commenters argue that 

more information should be posted on 

OASIS beyond what was proposed in 

the NOPR.478 EEI asserts that the details 

the transmission customers should 

report on the OASIS and in the 

quarterly reports include: The identity 

of the primary market seller; the 

identities of the secondary market seller 

and purchaser; the points of receipt and 

delivery; the term of reassigned service; 

the quantity of the reassigned service; 

and the charge for the reassignment, 

expressed in dollars per MW-month, 

week, day, or hour as appropriate. Other 

commenters contend that the existing 

quarterly report is appropriate and a 

new report should not be instituted.479

TranServ argues that the existing OASIS 

posting template query and audit 

functions are sufficient and no new 

obligations should be required. As to 

frequency of OASIS postings, Seattle 

suggests seven days after a transaction 

and NorthWestern proposes that the 

OASIS postings be no more frequent 

than monthly. 

804. Other commenters raise 

confidentiality concerns or state that 

business practice standards for capacity 

reassignment posting requirements 

would be required.480 Because these 

negotiated rates will be market 

sensitive, Allegheny asks the 

Commission not to require reporting 

and OASIS posting until the term of the 

reassignment has expired. NAESB states 

that capacity reassignment, including 

removing the price cap and allowing 

negotiated rates, could require posting 

standards for OASIS sites and the 

addition of significant functions to 

support such postings. 

805. NAESB states that capacity 

reassignment including removing the 

price cap and allowing negotiated rates 

could require posting standards for the 

OASIS site, and significant functions 

added to support such postings. NAESB 

asserts that this will require a more 

comprehensive standards solution, 

which may include data aggregation by 

the transmission provider, reports 

prepared and posted quarterly including 

how the information is communicated 

between the transmission provider and 

marketer for collection, submittals of 

quarterly reports from the transmission 

provider to the Commission, changes to 

the OASIS S&CP, and determination of 

informational content and design of 

templates. NAESB states that posting is 

more complicated if the transmission 

provider is required to post information 

given to it by a marketer on its nonstandard products and requests 

Commission guidance regarding posting 

requirements. 

Other Issues 

806. Some commenters argue that 

price caps are not limiting capacity 

reassignment under the current pro 

forma OATT.481 Williams contends that 

other non-price limitations on capacity 

reassignment, such as the requirement 

that the assignee utilize the same source 

and sink as the original customers, are 

the real reasons there has not been more 

capacity reassignment. Williams 

acknowledges that this bars network 

customers from reassigning 

transmission capacity and requests that 

Commission clarify that classification of 

a transmission customer as a network or 

point-to-point customer does not restrict 

the purchase or reassignment of 

transmission capacity. Sacramento 

similarly complains that one of the chief 

impediments to capacity reassignment 

is that network integration service 

customers are not permitted either to 

assign their capacity or to utilize it to 

make off-system sales. Sacramento 

contends that a point-to-point customer 

may utilize otherwise unused capacity 

to make sales ‘‘off-system’’ to third 

parties, while network customers cannot 

make full use of the transmission 

capacity for which they are paying. 

807. Some commenters contend that 

timelines for the release of capacity 

should be clearly stated.482 APPA 

argues that section 13.8 of the pro forma 

OATT provides too little time for LSEs 

attempting to make firm power supply 

arrangements to obtain even daily firm 

point-to-point service using the capacity 

left unscheduled by other firm point-topoint customers. Powerex and SPP also 

ask the Commission to set out clear 

rules, including timelines, for releasing 

unused transmission capacity for nonfirm use to better encourage full and 

economically efficient use of the 

existing transmission grid. 

Commission Determination 

808. To foster the development of a 

more robust secondary market for 

transmission capacity, the Commission 

concludes that it is appropriate to lift 

the price cap for all transmission 

customers reassigning transmission 

capacity. In Order No. 888, the 

Commission found that allowing 

holders of firm transmission capacity 

rights to reassign capacity would help 

parties manage the financial risks 

associated with their long-term 

commitments, reduce the market power 

of transmission providers by enabling 

customers to compete, and foster 


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483Order No. 888 at 31,696. 

484Because Order Nos. 888 and 888–A require a 

separation of a public utility’s transmission 

function and its wholesale generating marketing 

(merchant) function, a transmission provider will 

take service under its OATT through its merchant 

function or affiliate. 

485Order No. 888 at 31,696–97; Order No. 888–

A at 30,219–25. 

486Order No. 888 at 31,697. 

487As explained in section V.D.3, the Final Rule 

extends from one year to five years the minimum 

term required to obtain a rollover right. 

488Order No. 888 at 31,693. 

489See Southwestern Public Service Company, 80 

FERC ¶ 61,245 at 61,905 (1997). 

490Moreover, Order No. 889 required that all 

public utilities establish or participate in an OASIS 

that meets certain specifications and comply with 

Standards of Conduct designed to prevent 

employees of a public utility (or any employees of 

its affiliates) engaged in wholesale power marketing 

functions from obtaining preferential access to 

pertinent transmission system information. The 

Standards of Conduct mitigate the ability of an 

affiliate to hoard capacity or collect rates that are 

inconsistent with market conditions. As a result, we 

are less concerned in this instance about affiliates 

competing on the same terms as non-affiliates. To 

the extent problems arise from affiliate participation 

in the secondary capacity market, we will revisit 

our decision here to lift the price caps for 

transmission providers and their affiliates. 

efficient capacity allocation.483 Over the 

past ten years, however, it has become 

clear that capacity reassignment has 

failed to develop into a competitive 

alternative to primary capacity. In 

particular, the price cap has served to 

reduce customers’ transmission options 

and impaired the development of a 

secondary market for transmission 

capacity. In order to achieve the goals 

originally stated in Order No. 888, we 

therefore lift the price cap for reassigned 

capacity. We believe this will allow 

capacity to be allocated to those entities 

that value it most, thereby sending more 

accurate price signals to identify the 

appropriate location for construction of 

new transmission facilities to reduce 

congestion. 

809. We decline to adopt the NOPR 

proposal to retain price caps for 

capacity resold by a transmission 

provider’s merchant function or its 

affiliates.484 After reviewing the 

comments submitted in response to the 

NOPR, and further considering our ten 

years of experience regulating capacity 

reassignments, we conclude that 

retaining the price caps for this portion 

of the market would continue to impair 

development of the secondary market 

and is not otherwise necessary to ensure 

just and reasonable rates. We find there 

are no significant market power 

concerns to justify retaining the price 

caps for any transmission customer. 

Indeed, the Commission did not 

distinguish between affiliated and nonaffiliated transmission customers when 

it initially found in Order Nos. 888 and 

888–A that excess capacity reserved 

could be reassigned.485 The Commission 

instead placed a price cap on all 

reassignments of capacity out of a 

concern that the entire market for 

reassigned capacity was not sufficiently 

competitive.486 We now find that 

market forces, combined with the 

requirements of the pro forma OATT as 

modified in this Final Rule, will limit 

the ability of assignors to exert market 

power, including affiliates of the 

transmission provider. First, 

competition among reassigning 

customers will restrict the exercise of 

market power. Second, the continued 

regulation of rates for primary capacity 

will act as a further check to ensure 

rates for reassigned capacity remain just 

and reasonable. Finally, the amended 

rules we adopt below to govern the 

reassignment of capacity will increase 

our regulatory oversight of the 

secondary capacity market, allowing us 

to effectively monitor the secondary 

capacity market. There is thus no need 

to retain the existing price caps on 

reassigned capacity for any market 

participant. 

810. Our decision to lift the price caps 

for capacity reassignments by all 

transmission customers is motivated by 

growing concerns regarding the decrease 

in transmission investment and the 

corresponding increase in congestion 

costs, as described more fully in section 

III.C of this Final Rule. The Commission 

believes it is important to take every 

opportunity to explore more efficient 

use of the grid by industry participants, 

whether they are affiliates of the 

transmission provider or not. 

Eliminating the price cap for reassigned 

capacity will provide greater flexibility 

to respond to changing system 

conditions and alternatives for 

customers that value the capacity more 

highly. As commenters suggest, lifting 

the price cap will enhance the ability of 

customers that reserve long-term 

capacity for five-year terms in order to 

obtain rollover rights to resell that 

capacity if their needs change.487 Other 

customers may determine that it is more 

economic to acquire reassigned capacity 

reflecting market rates than reserve 

long-term capacity. In either case, lifting 

the price cap will help ensure that, 

during peak demand periods, 

transmission capacity will be used by 

those that value it the most. Establishing 

a competitive market for secondary 

transmission capacity will thus send 

more accurate price signals that promote 

efficient use of the transmission system 

by fostering the reassignment of unused 

capacity. 

811. While some commenters argue 

that lifting the cap encourages the 

exercise of market power, including 

hoarding, and discourages transmission 

investment, we find that competition 

among reassigning customers, 

continuing rate regulation of the 

transmission provider’s primary 

capacity, and reforms to the secondary 

capacity market adopted below, 

combined with enforcement 

proceedings, audits, and other 

regulatory controls, will assure just and 

reasonable rates. The Commission 

discussed the possibility of transmission 

capacity hoarding in Order No. 888. The 

Commission noted that unscheduled 

firm capacity is available on a non-firm 

basis to other customers and, thus, there 

is little practical possibility of hoarding. 

Instead, the capacity reassignment 

provisions of the pro forma OATT 

provide an economic incentive to make 

that capacity available to third 

parties.488 This applies even when the 

entity obtaining transmission capacity 

under the pro forma OATT is the 

transmission provider.489 It is equally in 

the corporate interests of a transmission 

provider and its affiliates not to overreserve or ‘‘hoard’’ transmission 

capacity. Under the pro forma OATT, 

the affiliate—and therefore the upstream 

corporate parent of the affiliate and the 

transmission provider—bears the cost 

responsibility for transmission capacity 

that it reserves but does not use to make 

wholesale sales. If the affiliate attempts 

to hoard transmission capacity, its 

upstream corporate parent loses 

revenues just like the non-affiliate. Like 

any other customer, an affiliate of the 

transmission provider should find it in 

its overall corporate interest to reassign 

transmission capacity to others with 

higher valued uses at negotiated 

rates.490

812. We reject the suggestion in the 

NOPR that lifting the price caps for the 

transmission providers’ merchant 

function or affiliates will provide 

disincentives to build or expand the 

transmission system. Without 

congestion, the transmission provider’s 

rate on file will serve as the de facto 

price cap and, if congestion exists, the 

‘‘incremental rate’’ reflecting the 

transmission provider’s cost of 

expanding the system should act as a 

price ceiling for long-term transactions. 

It would be unreasonable to expect a 

transmission customer to pay a rate for 

reassigned capacity that is higher than 

the cost of expansion when it could 

simply exercise its rights under the pro 

forma OATT as a cheaper alternative. 

To the extent there is a lag-time between 

the request for new transmission service 


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491Order No. 637–A at 31,595. 

492Our findings here address the particular 

circumstances associated with the electric utility 

industry and are not intended to suggest that 

corresponding changes should be made to the rates 

for capacity release by customers of natural gas 

transportation capacity. Any such changes would 

be considered only after notice and comment and 

based on a record applicable to the natural gas 

industry. 

493See Order No. 888 at 31,697. 

494See Order No. 888 at 31,697 n.394; Order No. 

888–A at 30,224 n.151. 

495The pro forma Form of Service Agreement for 

the Resale, Reassignment or Transfer of Long-Term 

Firm Point-to-Point Transmission Service is set 

forth in a new Attachment A–1 to the pro forma 

OATT. 

496As reformed in this Final Rule, the structural 

mechanism for reassigning transmission capacity 

will be similar to the mechanism for releasing 

pipeline capacity. While parties may be able to 

negotiate the prices applicable to assigned capacity, 

the assignee will execute a service agreement 

directly with the transmission provider and, thus, 

there will no longer be a need for the assigning 

party to have on file with the Commission a rate 

schedule governing reassigned capacity. See Order 

No. 888 at 31,697 n. 324. The transmission 

provider’s OATT will govern the reassigned service. 

The assignee will pay the transmission provider for 

service at the negotiated rate and the transmission 

provider will bill or credit the assignor with any the 

difference between the negotiated rate and the 

assignor’s original rate. As noted above, however, 

there will be no requirement for the transmission 

provider to create an auction for reassigned 

transmission capacity similar to the pipeline 

capacity reassignment program, since the 

underlying price caps are being removed for electric 

transmission capacity. 

497To the extent the assignee desires to change 

its points of receipt or delivery, the limitations set 

forth in section 23.2 shall apply. 

498See Commonwealth Edison Co., 78 FERC ¶

61,312 at 62,336 (1997); Boston Edison Co., 81 

FERC ¶ 61,372 at 62,768 (1997); Southwestern 

Public Service Co., 80 FERC ¶ 61,245 at 61,905 

(1997). The non-rate terms and conditions of 

reassigned service will therefore conform to the pro 

forma OATT. As a result, there is no requirement 

to file with the Commission service agreements for 

reassigned transmission service. 

and the date on which new facilities 

would be available, the adoption of 

conditional firm service and 

modifications to redispatch service 

elsewhere in this Final Rule will 

mitigate the exercise of market power 

during the interim period. We believe 

that the reforms to rules governing 

reassignments of capacity discussed 

below, along with associated reporting 

obligations, will adequately limit the 

ability of capacity holders to exercise 

market power in the limited 

circumstances when neither primary 

transmission capacity nor these 

additional services are available. 

813. Several commenters raise 

concerns that lifting of the price ceiling 

could lead to speculative pricing. If high 

prices occur during periods of peak 

demand it is a legitimate reaction to 

supply and demand forces. As we 

explained in Order No. 637–A, ‘‘[a] 

surge in the price of candles during a 

power outage is not evidence of 

monopoly in the candle market.’’ 491 To 

the extent that capacity is not being 

anticompetitively withheld from the 

market, high prices are the competitive 

responses to market conditions and 

should result in a more efficient 

allocation of capacity to those customers 

valuing it the most and a resulting 

expansion of transmission facilities. 

814. We emphasize that we are not 

deregulating or otherwise adopting 

market-based rates for the provision of 

transmission service under the pro 

forma OATT. Transmission providers 

will continue to be obligated to make 

ATC available to customers, including 

ATC associated with purchased but 

unused capacity. Transmission 

providers also will continue to be 

obligated to construct new facilities to 

satisfy a request for service if that 

request cannot be satisfied using 

existing capacity. The pro forma OATT 

therefore does not, and will not, permit 

the withholding of transmission 

capacity in an effort to exercise market 

power. Furthermore, the rates for 

transmission service provided under the 

pro forma OATT will continue to be 

determined on a cost-of-service basis 

unless the transmission provider can 

demonstrate, on a case-specific basis, 

that it lacks market power. Nothing in 

this Final Rule affects the obligations of 

transmission providers to offer service 

under the pro forma OATT at cost-based 

rates. The only reform being adopted 

concerns the resale of capacity by 

transmission customers. Given that 

traditional regulation will continue to 

govern the sale of primary capacity 

under the pro forma OATT, we no 

longer believe that cost-of-service 

regulation is necessary or appropriate 

for secondary capacity.492

815. As with any innovative rate 

program, however, the Commission will 

monitor the secondary capacity market 

to ensure that participants are not 

exercising market power. To enhance 

oversight and monitoring by the 

Commission, we adopt reforms to the 

underlying rules governing capacity 

reassignments. First, we require that all 

sales or assignments of capacity be 

conducted through or otherwise posted 

on the transmission provider’s OASIS 

on or before the date the reassigned 

service commences. The Commission 

thus eliminates the current ability of 

transmission customers to assign the 

transmission rights to another party 

with subsequent notification to the 

transmission provider.493 The 

mechanisms for negotiating a 

reassignment remain the same. The 

transmission customer may either 

request that the transmission provider 

make the capacity available on its 

OASIS or the transmission customer 

may negotiate the terms of an 

assignment bilaterally. In either 

instance, however, the resulting sale or 

assignment must be posted by the 

transmission provider on its OASIS 

prior to the date the reassigned service 

commences. We require transmission 

providers working through NAESB to 

develop appropriate OASIS 

functionality to allow such postings. 

Transmission providers need not 

implement this new OASIS 

functionality and any related business 

practices until NAESB develops 

appropriate standards. 

816. Second, we require that assignees 

of transmission capacity execute a 

service agreement prior to the date on 

which the reassigned service 

commences. Under the current pro 

forma OATT, transmission customers 

that have executed service agreements 

may negotiate and implement 

assignments of capacity without 

involving the transmission provider, 

subject to after-the-fact reporting and 

posting, provided the transmission 

customer has a market-based rate tariff 

on file.494 In order to increase our 

oversight of reassigned capacity, we find 

that all reassignments must instead be 

accomplished by the assignee executing 

a service agreement with the 

transmission provider that will govern 

the provision of reassigned service.495

This will effectively return the specified 

capacity to the transmission provider for 

the purpose of reassignment to the 

assignee.496 The assignment shall be 

only to the specified assignee, without 

any obligation that the capacity be made 

available to third parties, and shall not 

be subject to any queuing by the 

transmission provider since the assignee 

is merely accepting the assignor’s 

already-approved service for a specified 

period.497 All of the non-rate terms and 

conditions that otherwise would apply 

to the transmission provider’s sale of 

transmission capacity continue to apply 

in the case of a reassignment.498

817. Third, in addition to existing 

OASIS posting requirements, we require 

transmission providers to aggregate and 

summarize in an electronic quarterly 

report the data contained in these 

service agreements. As proposed in the 

NOPR, the use of quarterly reports will 

assist the Commission in gathering data 

to ensure the effectiveness of market 

forces and regulatory requirements to 

mitigate the exercise of market power. 

The Commission directs that this 

quarterly report be submitted 

electronically in spreadsheet format 


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499The transmission provider should identify 

capacity reassignments in the Contracts tab of the 

EQR using the Product Type Name ‘‘CAPACITY 

REASSIGNMENT.’’ All terms must be fully 

described and rates provided. If no Product Name 

adequately captures the nature of a given aspect of 

the capacity reassignment, the assignor may use the 

Product Name ‘‘OTHER,’’ but that aspect must be 

fully described in the Rate Description field. If that 

description is over 150 characters, the transmission 

provider may use multiple Contract Product lines 

to describe it. General instructions on how to file 

the EQR may be found at http://www.ferc.gov/docsfiling/eqr.asp. 

500See Alternatives to Traditional Cost-of-Service 

Ratemaking for Natural Gas Pipelines and 

Regulation of Negotiated Transportation Services of 

Natural Gas Pipelines, 74 FERC ¶ 61,076 (1996). 

501 Farmers Union Central Exchange v. FERC, 734 

F.2d 1486, 1501 (D.C. Cir. 1984) (Farmers Union) 

(finding that Commission failed to justify relaxation 

of cost-based regulation of oil pipeline companies 

because it did not ensure rates would remain within 

the zone of reasonableness). 

502Order No. 637–A at 31,558–72. 

503 Interstate Natural Gas Association of America 

v. FERC, 285 F.3d 18 (D.C. Cir. 2002). 

504Market participants may contact the 

Commission’s Enforcement Hotline via telephone 

(202) 502–8390, toll-free 1–888–889–8030, fax (202) 

208–0057, or at http://www.ferc.gov/cust-protect/ 

enforce-hot.asp. 

505Order No. 889 at 31,625. 

506See Order No. 2001 at P 94–129. 

507Order No. 888 at 31,696; Order No. 888–A at 

30, 223. 

consistent with the electronic filing 

system used for Electric Quarterly 

Reports so that it is readily accessible to 

the Commission and the public.499

818. Taken together, these reforms to 

the rules governing reassigned capacity 

will increase transparency and facilitate 

our monitoring of the secondary market 

for transmission capacity. We do not 

believe it is necessary to require a 

market power analysis as a condition to 

exercising the right to reassign 

transmission capacity. Although market 

power analyses are one method for 

ensuring that market-based rates remain 

just and reasonable, they are not the 

only method.500 To achieve the 

Commission’s original goals for capacity 

reassignment expressed in Order No. 

888, we adopt a more flexible approach 

in this area and rely on posting 

requirements and other regulatory 

controls to ensure that rates for 

reassigned transmission capacity remain 

just and reasonable. As noted above, we 

find that a market power analysis is not 

required because transmission providers 

continue to be obligated to satisfy 

requests for service—whether out of 

existing capacity or new facilities—at 

cost-based rates. Transmission capacity 

therefore cannot be withheld in an effort 

to exercise market power. Moreover, the 

posting and filing requirements adopted 

herein provide the Commission the 

necessary information to ensure that, 

even if an entity sought to exercise 

market power in the secondary market, 

such an attempt could be effectively 

detected. 

819. We therefore disagree with 

commenters who assert that lifting the 

cap on reassignment contradicts judicial 

and Commission precedent. In Order 

No. 637–A, the Commission explained 

at length why Farmers Union 501 and 

other precedent did not prevent the 

Commission from adopting negotiated 

rates for secondary capacity as part of a 

regulatory scheme that provides 

safeguards to ensure that rates remain 

just and reasonable.502 The court 

affirmed the Commission’s removal of 

price ceilings for short-term capacity 

release shippers in the natural gas 

market established in Order Nos. 637 

and 637–A, recognizing that non-cost 

factors such as the need to lift price 

ceilings to facilitate movement of 

capacity into the hands of those who 

value it most and the negotiated rates 

only to the secondary market 

distinguished the case from Farmers 

Union.503 The same is true here, given 

the non-cost factor advantages of lifting 

the price cap and the use of monitoring 

and enforcement of remedies to mitigate 

the exercise of market power. 

820. The Commission directs staff to 

closely monitor the reassignmentrelated data submitted by transmission 

providers in their quarterly reports to 

identify any problems in the 

development of the secondary market 

for transmission capacity and, in 

particular, the potential exercise of 

market power. We direct staff to 

prepare, within six months of receipt of 

two years of quarterly reports, a report 

summarizing its findings. To inform our 

analysis, we encourage market 

participants to provide feedback 

regarding the development of the 

secondary capacity market and, in 

particular, to contact the Commission’s 

Enforcement Hotline 504 with any 

particular concerns as this market 

develops. 

821. Although several commenters 

argue that additional posting and filing 

requirements could be too burdensome 

and costly, the Commission does not 

believe this burden will be great. All 

capacity reassignments must be 

conducted or otherwise posted on 

OASIS and each assignee will be 

required to submit an executed service 

agreement for reassigned service. The 

transmission provider thus will have 

ready access to data necessary for the 

OASIS postings and electronic quarterly 

transaction reports. In any event, the 

Commission’s access to this data is vital 

to ensure effective monitoring and 

oversight and, thus, we find that any 

burden on the transmission provider is 

outweighed by the need for 

transparency. To the extent the 

transmission provider incurs costs to 

maintain or report this information, 

Order No. 889 made clear that all OASIS 

users, including the transmission 

provider, pay all of the fixed costs of 

OASIS-related activities in wholesale 

rates and pay usage-related variable 

costs and fees.505

822. With regard to confidentiality 

concerns, the Commission finds that the 

disclosure of reassigned capacity 

information is necessary for the 

Commission and market participants to 

effectively monitor transactions for 

undue discrimination and preference. 

Consistent with our determination in 

Order No. 2001, where similar concerns 

were raised regarding disclosure of 

information, we believe that disclosure 

will promote competition and make the 

market operate more efficiently.506

Moreover, public reports will provide 

customers with a certain level of price 

transparency to help them make 

informed decisions regarding the 

relative value of capacity on a particular 

path. 

823. We decline requests to require 

implementation of electronic auctions 

for reassigned capacity. While such 

mechanisms are in place in RTO and 

ISO markets, we conclude that it would 

be too great a burden to impose 

electronic auctions on other 

transmission providers simply to 

facilitate capacity reassignments. The 

continued use of OASIS, combined with 

the posting and service agreement 

requirements adopted here, should be 

sufficient to facilitate more efficient use 

of the grid and mitigate the exercise of 

market power. 

824. With regard to the requests that 

the Commission institute alternative 

specific timelines and other rules for the 

reassignment of capacity rights to 

ensure efficient use of the grid, we will 

not revise the rules set forth in the pro 

forma OATT. We do not have sufficient 

evidence in this proceeding to suggest 

that public utilities’ existing scheduling 

timelines generally hinder customers 

from reselling unused transmission 

capacity or lead to capacity 

withholding. 

825. With regard to requests for 

network customers to reassign 

transmission capacity, we affirm our 

finding in Order Nos. 888 and 888–A 

that capacity reassignments are 

available only to point-to-point 

customers.507 Point-to-point service 

under the pro forma OATT clearly sets 

forth defined capacity rights and is 

therefore reassignable. In comparison, 


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12370 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

508 In the NOPR, we referred to an unreserved use 

penalty as an ‘‘unauthorized use penalty.’’ For the 

purpose of the Final Rule, we adopt the term 

‘‘unreserved use penalty’’ as it more clearly 

articulates the nature of the penalty. 

509E.g., APPA and Bonneville. 

510E.g., MidAmerican, Southern, and PNM–

TNMP. 

511E.g., APPA, TAPS, TDU Systems, and EEI 

Reply. 

there are no specific capacity rights 

associated with network service and, 

thus, that service is not reassignable. 

Network service provides a network 

customer with a right to integrate its 

designated resources with its designated 

loads, in a generation pattern primarily 

determined by the customer. As a result, 

it would be difficult to determine at any 

moment in time exactly what portion of 

network service could be resold, 

because the network customer does not 

have a discrete capacity reservation and 

its usage of the transmission system 

varies as it attempts to most 

economically use its resources to meet 

its loads. To the extent an entity elects 

network service, it does so with the 

understanding that the service is not 

reassignable because there are no 

specific capacity rights to reassign. 

5. ‘‘Operational’’ Penalties 

a. Unreserved Use Penalties 

NOPR Proposal 

826. In the NOPR, the Commission 

proposed to clarify that unreserved use 

penalties apply to any circumstance 

where a transmission customer uses 

transmission service that it has not 

reserved.508 Specifically, the 

transmission customer would be subject 

to an unreserved use penalty in 

circumstances where the transmission 

customer has a transmission service 

reservation, but uses transmission 

service in excess of its reserved 

capacity. A transmission customer also 

would be subject to an unreserved use 

penalty if the transmission customer 

uses transmission service where it does 

not have a transmission service 

reservation. The Commission also 

proposed that a transmission customer 

would not be subject to an unreserved 

use penalty in circumstances where the 

transmission customer inappropriately 

uses a network service reservation to 

support an off-system sale. 

827. The Commission sought 

comment on whether the current policy 

that limits unreserved use penalties to 

twice the standard rate for the entire 

service period has resulted in penalties 

that are not just and reasonable and, if 

so, it sought further comment regarding 

provisions that would yield unreserved 

use penalties that are just and 

reasonable. 

(1) Unreserved Use of Transmission 

Service 

Comments 

828. Several commenters express 

general support for the Commission’s 

proposed clarification that unreserved 

use penalties apply to any circumstance 

where a transmission customer uses 

transmission service that it has not 

reserved.509 Several commenters 

support the Commission’s proposed 

clarification, but suggest that the 

transmission provider should only 

assess unreserved use penalties when a 

transmission customer repeatedly uses 

transmission service that it has not 

reserved.510 For instance, PNM–TNMP 

believes penalty assessment should be 

optional and should be imposed on 

transmission customers that do not 

change their practices regarding 

transmission use and OATT compliance 

after being advised of their noncompliance. 

829. Several commenters argue that 

transmission customers with special 

circumstances should not be subject to 

unreserved use penalties in the same 

manner as other transmission 

customers. For instance, Seattle believes 

unreserved use penalties can result in 

charges that are unjust and reasonable 

for intermittent resources, such as wind 

generators, that can not precisely 

schedule power in future periods, but 

are capable of controlling output. Seattle 

believes that unreserved use penalties 

should not apply if the transmission 

provider is able to operate the 

transmission system reliably. Seattle 

argues that an unreserved use penalty 

should only apply if scheduling parties 

have failed to respond to dispatchers’

orders stating that system conditions 

necessitate curtailment of output. 

Southern disagrees with Seattle and 

states that, as a general principle, 

unreserved use penalties should not be 

based on whether reliability is 

threatened. TDU Systems recommend 

that the Commission consider treating 

inadvertent use of point-to-point 

transmission service in excess of 

reservations by an entity serving native 

load in multiple control areas as an 

energy imbalance in the control area in 

which the energy imbalance occurs, 

rather than an unreserved use of pointto-point service. In their reply 

comments, EEI and PNM–TNMP 

disagree with TDU Systems. EEI argues 

that energy imbalance charges 

compensate generators for the 

additional expense they incur to 

compensate for the customer’s failure to 

schedule sufficient energy to serve its 

load and do not compensate the 

transmission provider for the use of the 

transmission system. EEI asserts that 

customers that use more transmission 

service than they schedule should be 

required to pay for that transmission 

service just like any other user of the 

system. 

830. Duke opposes the Commission’s 

proposed clarification and suggests that 

an effective means of deterring and 

punishing unreserved use of 

transmission service is to charge the 

customer for the point-to-point service 

necessary to support the transaction 

and, additionally, to make the customer 

subject to a civil penalty in cases of 

intentional or repeated unreserved use. 

TDU Systems argue on reply that a 

transmission provider should not be 

allowed to charge unreserved use 

penalties unless it employs software 

technology designed to identify 

unreserved use prior to operation. 

831. Several commenters suggest 

modifications to the manner by which 

transmission providers determine when 

unreserved use penalties should be 

assessed. TDU Systems believes 

unreserved use penalties should only be 

applied with prior Commission 

approval after notice and opportunity 

for hearing in order to limit the 

transmission provider’s discretion in 

applying such penalties. To encourage 

regulatory certainty, Seattle suggests 

that the Commission implement tariff 

provisions that state a clear basis for 

application of unreserved use penalties. 

832. Several commenters ask that the 

Commission delete the proposed 

language added to section 30.4 of the 

proposed revised pro forma OATT 

regarding the unreserved use of a 

network resource beyond its designated 

capacity.511 In the event the 

Commission elects to retain this 

language, these commenters ask the 

Commission to clarify the language to 

expressly permit use of the 

undesignated portion of a remote 

network resource under secondary nonfirm service (as a non-network resource) 

and to preserve the customer’s right to 

use the undesignated portion of the 

resource for other purposes (e.g., to 

serve its load on systems other than the 

host transmission provider or to make 

off-system sales). In its reply comments, 

Duke notes that the fact that a generator 

is designated as a network resource for 

a network load on one system does not 

prohibit a network load on a second 

system from obtaining non-firm energy 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12371 

512Arizona Public Service Co., 109 FERC ¶ 61,271 

at P 6 (2004) (APS). APS contained two findings 

that Commission audit staff characterized as 

unauthorized use of transmission service. In the 

first finding, APS’s wholesale merchant function 

did not request and pay for point-to-point service 

to support some of the off-system power sales it 

made at trading hubs where APS system resources 

were directly connected. In the second finding, APS 

incorrectly treated the Phoenix Valley 230kV 

system as a single node on its transmission system. 

As a result, off-system sales made by generators 

connected to the Phoenix Valley system should 

have been, but were not, supported by point-topoint service. 

513The unreserved use penalties thus work in 

conjunction with imbalance penalties described in 

section V.C.2 of this Final Rule to reduce incentives 

to take actions that impair the reliability of the 

transmission system. 

from that same generator using point-topoint and secondary network resource. 

Duke points out that the proposed 

revised section 30.4 prohibits a network 

customer from using its firm network 

service to schedule power in excess of 

the DNR amount. Finally, TAPS asks the 

Commission to modify the language 

added to section 30.4 so that its terms 

are consistent with the terms used in the 

rest of the pro forma OATT. 

833. EEI recommends that a customer 

that takes unreserved transmission 

service, but that does not have a service 

agreement with the transmission 

provider, be deemed to have consented 

to the transmission provider’s filing of 

a service agreement, so that the 

transmission provider has a basis for 

imposing both the prevailing OATT rate 

and the penalty charge on the customer. 

EEI also recommends that the 

Commission clarify that a customer that 

uses more transmission service than it 

has reserved also is subject to charges 

for ancillary services. 

Commission Determination 

834. The Commission adopts the 

NOPR proposal that a transmission 

customer will be subject to unreserved 

use penalties in any circumstance where 

the transmission customer uses 

transmission service that it has not 

reserved. Specifically, a transmission 

customer will be subject to an 

unreserved use penalty in 

circumstances where a transmission 

customer has a transmission service 

reservation, but uses transmission 

service in excess of its reserved 

capacity. A transmission customer also 

will be subject to an unreserved use 

penalty if the transmission customer 

uses transmission service where it does 

not have a transmission service 

reservation, including the situations 

described in the Arizona Public Service 

Company (APS) audit report.512 We note 

that the transmission provider is subject 

to the same penalties when it takes 

transmission service under its OATT. 

835. Our decision to clarify the 

application of unreserved use penalties 

will eliminate a potential source of 

discretion in the implementation of the 

pro forma OATT and will assist the 

Commission in its enforcement of the 

OATT obligations. The unreserved use 

penalty itself will help discourage 

disorderly use of transmission service. 

Charging a transmission customer for 

just the unreserved transmission service 

used, as suggested by Duke, would not 

provide a sufficient incentive to procure 

adequate transmission service, even 

with the threat of possible civil 

penalties. In addition, an operational 

penalty rather than a civil penalty is a 

more appropriate default remedy, even 

though certain circumstances may 

warrant a civil penalty in addition to an 

operational penalty. In most instances, 

an unreserved use penalty can be 

applied in a relatively mechanical 

manner. As a result, an operational 

penalty has a relatively low 

administrative burden and still provides 

a clear signal to transmission customers 

regarding the cost of non-compliance.513

We do not agree with TDU Systems’

proposal that a transmission provider be 

required to employ software designed to 

identify unreserved use if the 

transmission provider wants to charge 

unreserved use penalties. As we explain 

below, we adopt reforms in this Final 

Rule that will reduce the level of 

unreserved use penalties for instances of 

inadvertent unreserved use. For 

instance, we reduce the period over 

which a one-time inadvertent use will 

be penalized from one month to one 

day. We believe that this and other 

reforms are sufficient to address TDU 

Systems’ concerns. 

836. We will not adopt Seattle’s 

suggestion to add provisions to the pro 

forma OATT that specify all 

circumstances that constitute use of 

transmission service without a 

transmission service reservation. Any 

list of transmission customer actions 

that would be deemed to constitute use 

of transmission service without a 

transmission service reservation will 

necessarily be incomplete and out-ofdate given the dynamic manner by 

which trading patterns and practices 

evolve. We believe that Commission 

actions, such as in APS, will provide a 

sufficient guide to circumstances that 

constitute use of transmission system 

without a transmission service 

reservation. We also reject TDU 

Systems’ suggestion that unreserved use 

penalties be applied only after 

Commission approval. As mentioned 

above, an unreserved use penalty can be 

assessed in a relatively straightforward 

manner in most cases. As a result, there 

will typically be little need for the 

Commission to become involved. That 

said, a transmission customer can 

always file a complaint with the 

Commission protesting an unreserved 

use penalty. 

837. We will not exempt any class of 

transmission customer from the 

potential assessment of unreserved use 

penalties. We do not agree with Seattle’s 

assertion that unreserved use penalties 

can result in charges that are unjust and 

reasonable for intermittent resources, 

such as wind generators, that can not 

precisely schedule power in future 

periods. Unreserved use penalties are 

based on the transmission capacity 

reserved rather than the transmission 

service scheduled, so an intermittent 

resource’s inability to precisely 

schedule power in future periods is 

irrelevant, as long as the resource has 

reserved sufficient transmission 

capacity to deliver the resource’s full 

output. We also do not agree with TDU 

Systems’ suggestion that unreserved use 

of transmission service by an entity 

serving native load in multiple control 

areas should be treated as an energy 

imbalance in the control area in which 

the energy imbalance occurs, rather than 

an unreserved use of point-to-point 

service. In this regard, we agree with EEI 

that energy imbalance charges 

compensate the transmission provider 

for the additional expense it incurs to 

compensate for a transmission 

customer’s failure to schedule sufficient 

energy to serve its load and do not 

compensate the transmission provider 

for the use of the transmission system. 

838. We will not limit unreserved use 

penalties to instances where the 

unreserved use jeopardizes the reliable 

operation of the transmission system. 

Unreserved use penalties are intended, 

in part, to give transmission customers 

an incentive to reserve and pay for the 

appropriate level of transmission service 

so that transmission service is allocated 

in an orderly fashion. A transmission 

customer that uses unreserved 

transmission service requires the 

transmission provider to take some 

action to accommodate the additional 

use of the system. Some penalty is 

warranted even in those instances when 

the transmission provider’s 

accommodations are sufficient to avoid 

curtailment of transmission service to 

other transmission customers. Absent a 

penalty in all instances, transmission 

customers would have an increased 

incentive to under-reserve transmission 

service, which would lead to an 

increase in the likelihood that system 

reliability would be impaired. In 


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514See MidAmerican Energy Co., 112 FERC 

¶ 61,346 (2005); PacifiCorp, 118 FERC ¶ 61,026 

(2007). 

515See Order No. 888–A at 30,216–17. 

516See id. at 30,217. 517E.g., APPA and PNM–TNMP. 

518E.g., EEI, Bonneville, MidAmerican, Nevada 

Companies, and PNM–TNMP Reply. 

addition, a transmission customer that 

uses more transmission service than it 

has reserved, even in periods when 

system reliability has not been 

impaired, has nonetheless disturbed the 

orderly allocation of transmission 

service. 

839. In response to comments 

requesting that we remove the language 

added to section 30.4 of the proposed 

revised pro forma OATT regarding the 

unreserved use of a network resource 

beyond its designated capacity, we 

clarify our intent in modifying section 

30.4. The Commission has identified 

instances when a transmission provider 

has scheduled delivery of off-system 

non-designated short-term purchases 

using transmission capacity reserved for 

designated network resources.514 The 

intent of the language added to section 

30.4 of the pro forma OATT was to 

clarify that network customers are 

subject to unreserved use penalties 

when they schedule delivery of offsystem non-designated purchases using 

transmission capacity reserved for 

designated network resources. We 

clarify, however, that a network 

customer may use the undesignated 

portion of a remote network resource to 

serve network load using secondary 

network service and may use the 

undesignated portion of the resource for 

other non-network service purposes, 

such as third-party sales, as long as the 

network customer acquires the 

appropriate point-to-point transmission 

service. Moreover, because a 

transmission provider does not have to 

‘‘take service’’ under its own OATT for 

the transmission of power that is 

purchased on behalf of bundled retail 

customers, it is free to use the 

undesignated portion of a remote 

network resource to serve its bundled 

retail customers.515 If the transmission 

provider desires to use a remote 

network resource for non-native load 

purposes, such as third-party sales, it 

must acquire the appropriate point-topoint transmission service.516

840. In order to ensure that the 

transmission provider has a basis for 

charging an unreserved use penalty, we 

modify section 13.4 of the pro forma 

OATT to provide that a customer that 

takes unreserved point-to-point 

transmission service and does not have 

a service agreement with the 

transmission provider is deemed to have 

executed the transmission provider’s 

form of service agreement for point-topoint service. In addition, we clarify 

that a customer that uses more 

transmission service than it has reserved 

is also subject to charges for ancillary 

services. The ancillary service charges 

will be based on just the period of 

unreserved use. For instance, if a 

transmission customer has unreserved 

use during two hours on the same day, 

the customer must pay the ancillary 

service charges for those two hours, 

rather than for the entire day. This 

modification is appropriate, as the 

transmission provider is entitled to 

compensation for the ancillary services 

it provides when it provides 

transmission service. We also will 

modify section 3 of the pro forma OATT 

to reflect this rule. 

(2) Treatment of Inappropriate Use of 

Network Service as an Unreserved Use 

of Point-to-Point Transmission Service 

Comments 

841. A few commenters argue that a 

transmission customer that 

inappropriately uses a network service 

reservation to support an off-system sale 

should be subject to unreserved use 

penalties.517 Other commenters request 

clarification or modifications to the 

Commission’s proposal regarding the 

treatment of transmission customers 

that inappropriately use a network 

service reservation to support an offsystem sale. TAPS asks the Commission 

to clarify that a transmission provider 

that inappropriately uses network 

service to support an off-system sale is 

required to pay for point-to-point 

service to support the off-system sale 

and potentially is liable for civil 

penalties, as the Commission proposed 

in the NOPR. Suez Energy NA suggests 

that an affiliate of the transmission 

provider that violates network tariff 

provisions by making unauthorized 

sales should also disgorge unjust profits 

from such sales. TDU Systems urges the 

Commission not to impose civil 

penalties for inadvertent use of network 

service by an LSE when it serves its own 

native load on a neighboring system. 

Commission Determination 

842. The Commission declines to 

adopt the NOPR proposal to exempt a 

network customer or transmission 

provider that inappropriately uses 

network transmission service to support 

off-system sales from unreserved use 

penalties. As mentioned above, one of 

the purposes of unreserved use 

penalties is to encourage orderly use 

and acquisition of transmission service. 

A network customer or transmission 

provider that inappropriately uses 

network transmission service to support 

off-system sales potentially uses or 

acquires transmission service that 

should be allocated to other 

transmission customers. In addition, the 

network customer or transmission 

provider has not paid for transmission 

service as required. Therefore, we 

conclude that a network customer or 

transmission provider inappropriately 

using network transmission service to 

support off-system sales should be 

subject to unreserved use penalties. We 

will evaluate the appropriateness of 

civil penalties in addition to unreserved 

use penalties on a case-by-case basis 

and will not exempt, as a matter of 

general policy, inadvertent use of 

network service by an LSE when it 

serves its own native load on a 

neighboring system as suggested by 

TDU Systems. A network customer or 

transmission provider that 

inappropriately uses network 

transmission service to support offsystem sales also may be required to 

disgorge unjust profits from such sales, 

as the Commission may determine on a 

case-by-case basis. 

(3) Penalty Rate for Unreserved Use of 

Transmission Service 

Comments 

843. Transmission providers generally 

assert that the Commission’s current 

policy of limiting unreserved use 

penalties to twice the standard rate for 

the entire service period has yielded just 

and reasonable rates.518 EEI contends 

that if the customer is required to pay 

an unreserved use charge only for the 

period of unreserved use, the customer 

would have an incentive to reserve 

service for less than its maximum 

expected use and simply pay 

unreserved use charges in the hours in 

which it exceeds that usage. EEI 

concedes, however, that the maximum 

period for which the unreserved use 

charge should be assessed is one month. 

For example, EEI acknowledges that it 

would be unreasonable to charge a 

customer that takes yearly service a 

penalty for an entire year because of, for 

instance, a single hour of unreserved 

use. In addition, EEI suggests several 

modifications to the current unreserved 

use penalty policy. EEI suggests the 

Commission include, in the pro forma 

OATT, provisions stating that the 

penalty charge for unreserved use of 

transmission service is equal to twice 

the standard rate for transmission 

service. EEI recommends that the 

Commission establish a policy that a 


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519E.g., APPA, AWEA, TAPS, and TDU Systems. 

520E.g., APPA, AWEA, TAPS, and TDU Systems 

Reply. 

521E.g., NRECA, Nevada Companies, and 

Southern. 

522There are a number of possible permutations 

of these principles. For instance, a transmission 

customer that has 25 MW of unreserved use in two 

hours on one day during the first week of the month 

and 50 MW of unreserved use in two hours on one 

day during the last week of the month will pay an 

unreserved use penalty based on the rate for 25 MW 

of daily firm point-to-point service and 50 MW of 

daily firm point-to-point service. A transmission 

customer that has 25 MW of unreserved use on two 

separate days during the first week of the month 

and 50 MW of unreserved use in two hours on one 

day during the last week of the month will pay an 

unreserved use penalty based on the rate for 25 MW 

of weekly firm point-to-point service and 50 MW 

of daily firm point-to-point service. A transmission 

customer that has 25 MW of unreserved use on two 

separate days during the first week of the month 

and 50 MW of unreserved use on two separate days 

during the last week of the month will pay an 

unreserved use penalty on 50 MWs of monthly firm 

point-to-point service. 

523Allegheny Power System, Inc., 80 FERC 

¶ 61,143 at 61,545–46 (1997) (Allegheny). 

customer that uses transmission service 

without a reservation must pay a 

penalty equal to twice the rate for 

transmission service for the greater of 

the period of unreserved use or one 

month. 

844. Transmission customers 

generally assert that unreserved use 

penalties should be limited to twice the 

standard rate for the period of 

unreserved use.519 Transmission 

customers who take this position argue 

that using the service period rather than 

the period of unreserved use as the basis 

for the penalty charge discriminates 

against transmission customers with 

longer term transmission service 

reservations.520 For instance, AWEA 

believes that applying an unreserved 

use penalty based on the reservation 

period rather than the period of 

unreserved use has resulted in charges 

that are not just and reasonable. AWEA 

asserts that such a policy would also be 

discriminatory because, if the customer 

causing the unreserved use had made a 

shorter reservation, its penalty would be 

much lower. TDU Systems argue in its 

reply comments that there is little to be 

gained from charging inadvertent 

unreserved use more than twice the 

standard rate for the period of 

unreserved use. 

845. Several commenters suggest that 

unreserved use penalty charges greater 

than twice the standard rate for the 

entire service period should be limited 

to instances of intentional unreserved 

use.521 Nevada Companies note that 

there are some marketing entities that 

are consistently abusing the current 

policy and recommends that the 

Commission consider more severe 

penalties for continuous carelessness in 

tagging or a repeated pattern of 

unreserved use of the transmission 

system. Southern believes the 

transmission provider should be 

permitted to charge increased 

unreserved use penalties if a 

transmission customer consistently uses 

transmission services it has not 

reserved. TDU Systems disagree on 

reply comments, arguing that a penalty 

equal to twice the applicable charge is 

sufficient to deter unreserved use of 

transmission service. 

Commission Determination 

846. We will continue giving 

transmission providers discretion in 

setting their unreserved use penalty 

rates, although those rates will need to 

be consistent with this Final Rule. 

Penalty charges must be based on the 

period of unreserved use rather than the 

period for which service is reserved, 

subject to the following principles. First, 

the unreserved use penalty for a single 

hour of unreserved use will be based on 

the rate for daily firm point-to-point 

service, even if the transmission 

provider has a rate for hourly firm 

point-to-point transmission service on 

file. Second, as a general rule, more than 

one assessment for a given duration 

(e.g., daily) will increase the penalty 

period to the next longest duration (e.g., 

weekly). The unreserved penalty charge 

for multiple instances of unreserved use 

(i.e., more than one hour) within a day 

will be based on the rate for daily firm 

point-to-point service. The unreserved 

penalty charge for multiple instances of 

unreserved use isolated to one calendar 

week would result in a penalty based on 

the charge for weekly firm point-topoint. The unreserved use penalty 

charge for multiple instances of 

unreserved use during more than one 

week during a calendar month will be 

based on the charge for monthly firm 

point-to-point.522

847. Our determination is based, in 

part, on agreement with those 

commenters arguing that using the 

period for which a transmission 

customer has reserved service rather 

than the period of unreserved use as the 

basis for the penalty charge 

discriminates against transmission 

customers with longer term 

transmission service reservations. We 

are mindful, however, that basing 

unreserved use penalties on only the 

period of unreserved use could give the 

transmission customer an incentive to 

reserve service for less than its 

maximum expected use and simply pay 

unreserved use charges in the hours in 

which it exceeds that usage. We believe 

the unreserved penalty regime we 

articulate in this Final Rule will provide 

a reasonable incentive to ensure that 

transmission customers reserve the 

appropriate level of transmission service 

without unduly charging a transmission 

customer for inadvertent unreserved 

use. In addition, transmission customers 

will continue to be subject to civil 

penalties on a case-by-case basis, so 

attempts to game this penalty regime 

could result in additional penalties 

depending on the specific facts at issue. 

We reject the suggestion in some 

comments that the transmission 

provider should only assess unreserved 

use penalties where a transmission 

customer repeatedly uses transmission 

service that it has not reserved. Rather, 

we find that penalties are appropriate 

for all unreserved uses of the system. 

Because we are allowing penalties to be 

based on the period of unreserved use, 

not the reservation period, such 

penalties do not unduly charge a 

transmission customer for inadvertent 

unreserved use. This penalty regime 

will apply to all instances where a 

transmission customer has an 

unreserved use of transmission service, 

regardless of whether the transmission 

customer had an existing relevant 

transmission service reservation but for 

a lesser amount of service. 

848. A transmission provider that 

wants to charge unreserved use 

penalties must explicitly state the 

penalty rate in its tariff. The 

Commission retains the current policy 

established in Allegheny that the 

unreserved use penalty rate may not be 

greater than twice the firm point-topoint rate for the period of unreserved 

use, as defined above.523 We continue to 

believe that penalties up to twice the 

relevant firm point-to-point rate are just 

and reasonable, given the new 

definition for the penalty period. As a 

result, we establish a rebuttable 

presumption that unreserved use 

penalties no greater than twice the firm 

point-to-point rate for the penalty 

period defined above are just and 

reasonable. As we discuss above, the 

transmission customer must face a 

penalty in excess of the firm point-topoint transmission service charge it 

avoids through unreserved use of 

transmission service or the transmission 

customer will have no incentive to 

reserve the appropriate amount of 

service. 

849. The Commission thus concludes 

that a penalty of twice the standard rate 

is not excessively punitive, particularly 

given the definition of the penalty 

period established in this Final Rule. 

Without evidence to the contrary, we 


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524An operational penalty explicitly defines the 

charge associated with a set of pre-defined activities 

(e.g., unreserved use of transmission service, 

completing request studies outside of the 60-day 

due diligence deadline) that are not in compliance 

with specific provisions of the OATT. 

525E.g., APPA, ELCON, Entegra, TAPS, TDU 

Systems, Sacramento, and Seattle. 

526Entegra cites Carolina Power & Light Co. and 

Florida Power Corp., 103 FERC 61,209 at P 24 

(2003) (Carolina Power & Light). 

527E.g., EEI, MidAmerican, Nevada Companies, 

and PNM–TNMP. 

528E.g., EEI, Suez Energy NA, Sacramento, TAPS, 

and Wisconsin Electric. 

529E.g., Ameren and PNM–TNMP. 

believe an unreserved use penalty equal 

to twice the applicable rate should 

create the appropriate incentive to 

transmission customers to purchase the 

correct amount of transmission service. 

Nonetheless, we will allow transmission 

providers to make a filing under section 

205 of the FPA to propose an 

unreserved use penalty in excess of 

twice the relevant firm point-to-point 

rate for pervasive unreserved use. 

Transmission providers that propose 

such a rate must establish that a higher 

penalty rate is required to combat 

pervasive unreserved use of 

transmission. In arguing for such a 

higher penalty rate, the transmission 

provider must address why the standard 

penalty rate that penalizes repeated 

unreserved use is not adequate to 

discourage repeated instances of 

unreserved use of transmission service. 

b. Distribution of Operational Penalties 

NOPR Proposal 

850. In the NOPR, the Commission 

proposed to have the transmission 

provider distribute to non-offending, 

unaffiliated transmission customers 

operational penalties incurred by the 

transmission provider’s merchant 

function or its affiliates.524 For those 

transmission providers subject to 

operational penalties, the Commission 

proposed to require the transmission 

provider to make an annual compliance 

filing to notify the Commission of the 

amounts of such operational penalties 

incurred during the year and to propose 

a method to identify non-offending, 

unaffiliated transmission customers to 

which the transmission provider would 

distribute penalty amounts. In addition, 

the Commission also proposed to allow 

a transmission provider to avoid an 

annual compliance filing by making a 

one-time filing to propose a mechanism 

through which it would identify nonoffending, unaffiliated transmission 

customers and a method by which it 

would distribute the operational 

penalties it or its affiliates have incurred 

to the identified transmission 

customers. Finally, the Commission 

proposed to prohibit transmission 

providers from recovering for 

ratemaking purposes or through any 

service or facility under the 

Commission’s jurisdiction any cost it 

incurs when it or an affiliate pays an 

operational penalty. 

Comments 

851. Transmission customers along 

with several other commenters support 

the Commission’s proposal to distribute 

operational penalties paid by the 

transmission provider’s merchant 

function to non-offending, unaffiliated 

transmission customers.525 Entegra and 

Morgan Stanley advocate extending the 

proposal so that the transmission 

provider distributes operational 

penalties paid by all transmission 

customers to non-offending unaffiliated 

transmission customers. Entegra also 

notes that the Commission’s policy in 

the natural gas setting is that pipelines 

must credit all penalty revenues back to 

non-offending shippers. Entegra argues 

that the precedent the Commission cited 

in proposing that operational penalties 

paid by the transmission provider be 

distributed to non-offending, 

unaffiliated transmission customers 

applies equally to penalties paid by 

affiliated and unaffiliated transmission 

customers.526

852. With regard to unreserved use 

penalties, NRECA and TDU Systems 

argue that the Commission should 

encourage transmission providers to 

supervise inadvertent unreserved use 

and notify the customer of such 

occurrence rather than rely on large 

unreserved use penalties. They argue it 

is better to prevent unnecessary costs 

than to approve post hoc penalties for 

unintentional unreserved use that could 

have been prevented. 

853. A number of transmission 

providers oppose the portion of the 

Commission’s proposal that would 

prohibit their non-offending affiliates 

from receiving a portion of the 

operational penalties the transmission 

provider incurs.527 For instance, PNM–

TNMP asserts that the Commission 

should allow the transmission 

provider’s non-offending affiliates, 

which are abiding by the same rules as 

other transmission customers in 

accordance with Standards of Conduct, 

to be eligible to receive a portion of the 

operational penalties the transmission 

provider incurs. In the specific case of 

unreserved use penalties, Southern does 

not support distributing penalties 

imposed on a transmission provider’s 

affiliate to other OATT customers. 

Southern argues that such a proposal is 

predicated upon the false assumption 

that such penalties are not of true 

financial consequence. Southern asserts 

that penalties paid by an affiliate do, in 

fact, represent a real cost to the 

wholesale business of that affiliated 

entity. In its reply comments, TDU 

Systems disagrees with comments that 

suggest that non-offending affiliates 

should be allowed to receive a load ratio 

share of penalty revenues when a 

transmission provider or one of its 

affiliates incurs an operational penalty. 

TDU Systems argue that allowing any 

member of the corporate family to retain 

any portion of the penalty revenues 

incurred by another member of the 

corporate family will dilute the 

incentive inherent in the Commission’s 

proposal. 

854. Seattle suggests that compliance 

monitoring and enforcement to ensure 

that the transmission provider 

appropriately assesses penalties to its 

affiliates will be as important as 

correctly accounting for and distributing 

the revenues from penalties collected 

from affiliates. 

855. Most commenters were 

supportive of the Commission’s 

proposal to have transmission providers 

notify the Commission of the amounts 

of all operational penalties they 

incurred during the year through either 

an annual compliance filing or a onetime filing.528 Several commenters 

expressed a preference for a one-time 

filing by transmission providers.529 For 

instance, Ameren states that it prefers 

the use of a one-time filing to propose 

a mechanism through which the 

transmission provider would identify 

non-offending, unaffiliated transmission 

customers and a method by which the 

transmission provider would distribute 

the operational penalties it or its 

affiliates have incurred to the identified 

transmission customers. Ameren 

believes this would be less burdensome 

than an annual repeated compliance 

filing. TDU Systems, on the other hand, 

prefer the Commission’s proposal to 

require an annual reporting of penalties 

levied and penalty revenues credited in 

order to foster greater transparency on 

this matter. TDU Systems believe greater 

transparency through improved 

reporting requirements would provide 

greater opportunities for detecting 

abuses by transmission providers or 

their affiliates, either in imposing 

inappropriate penalties on transmission 

customers or in failing to penalize their 

own or their affiliates’ transgressions. In 

addition, TDU Systems suggest that this 

reporting requirement should include 

details on the amount of penalties 


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530As we explain further below, the transmission 

provider will be allowed to retain the base firm 

point-to-point transmission service charge when it 

assesses an unreserved use penalty. 

531Regulation of Short-Term Natural Gas 

Transportation Services, and Regulation of 

Interstate Natural Gas Transportation Services, 

Order No. 637, 65 FR 10156 (Feb. 25, 2000), FERC 

Stats. & Regs. ¶ 31,091 at 31,309 (2000) (‘‘* * *to 

effectively shift pipelines to the use of the nonpenalty mechanisms described above to solve and 

prevent operational problems, it will be necessary 

to eliminate the pipelines’ financial incentive to 

impose penalties and OFOs. Thus, the Commission 

is requiring pipelines to credit the revenues from 

penalties and OFOs to shippers.’’); order on reh’g, 

Order No. 637–A, 65 FR 35706 (Jun. 5, 2000), FERC 

Stats. & Regs. ¶ 31,099 at 31,609 (2000) (‘‘The goal 

of the Commission’s new policy on penalties is to 

encourage pipelines to rely less on penalties and 

more on non-penalty mechanisms to manage their 

systems* * *.’’). 

levied, whether on customers or the 

transmission provider or its affiliates, 

for all violations. With regard to the 

annual reporting requirements (for those 

companies that do not propose a 

standard mechanism to handle the 

distribution of penalties), Nevada 

Companies suggest that a standard 

template be proposed so that all 

companies are following the same 

reporting format. 

856. Several commenters make 

recommendations that they argue will 

ease the administrative burden of 

distributing operational penalties paid 

by the transmission provider to nonoffending, unaffiliated transmission 

customers. MidAmerican suggests that 

excluding short-term firm and non-firm 

transactions from the distribution 

methodology would avoid the need to 

develop a costly and administratively 

difficult program. TVA suggests that the 

amount of any such operational 

penalties should simply be a credit 

against the transmission provider’s 

transmission revenue requirement, 

thereby more efficiently reducing the 

cost of transmission service to 

transmission customers. 

857. Several commenters argue that 

the transmission provider must be made 

whole before it distributes any penalty 

revenues. For instance, EEI supports the 

Commission’s proposal to the extent 

penalty revenues exceed the cost of 

transmission service. Nevada 

Companies assert that it is the 

transmission provider’s native load that 

incurs the cost of correcting for the 

offending customer’s intentional 

deviation from schedule or for a 

transmission customer’s self-provided 

reserves being unavailable. Therefore, 

Nevada Companies contend that any 

penalties should be returned to the 

native load to offset its cost of 

generation. 

858. Sacramento and WPS 

Companies’ reply comments support the 

Commission’s proposal to prohibit a 

transmission provider from recovering 

any cost it incurs when it or an affiliate 

pays an operational penalty through 

jurisdictional rates or services. 

Commission Determination 

859. The Commission agrees with 

those commenters recommending that 

we broaden the NOPR proposal, which 

required transmission providers to 

distribute to non-offending, unaffiliated 

transmission customers only the 

unreserved use penalties the 

transmission provider’s merchant 

function incurs. Consistent with our 

conclusion regarding imbalance 

penalties, we conclude that it would be 

more appropriate for transmission 

providers to be required to distribute all 

unreserved use penalties they collect, 

whether from the transmission 

provider’s merchant function or other 

transmission customers. The penalties 

the transmission provider pays for late 

studies are penalties that, by their 

nature, are fully distributed only to nonaffiliated transmission customers. 

Requiring the transmission provider to 

distribute the unreserved use penalty 

charges that its merchant function 

incurs will ensure that the transmission 

provider faces a meaningful financial 

consequence when its merchant 

function incurs an operational penalty. 

Extending the NOPR proposal to all 

unreserved use penalty revenues the 

transmission provider collects 

maintains the incentive structure of the 

unreserved use penalty and prevents the 

transmission provider from retaining 

revenues above those it should 

reasonably be allowed to earn.530 This 

determination is consistent with the 

Final Rule for imbalance penalties and 

the Commission’s decision in Order 

Nos. 637 and 637–A.531

860. We agree with those commenters 

that suggest that non-offending affiliates 

of the transmission provider, including 

the transmission provider’s native load 

customers, should be eligible to receive 

a portion of the unreserved use 

penalties that the transmission provider 

collects. Unreserved use penalties are 

assessed against transmission customers 

and should, therefore, be distributed to 

all non-offending transmission 

customers, whether affiliated with the 

transmission provider or not. Given the 

distribution of unreserved penalties 

articulated above, the transmission 

provider’s corporate profit is reduced if 

one of the transmission provider’s 

wholly-owned marketing affiliates pays 

an operational penalty to the 

transmission provider. This is so 

because the corporate shareholders 

ultimately pay the marketing affiliate’s 

penalty, while the transmission 

provider distributes the revenues to 

non-offending transmission customers. 

861. The Commission requires the 

transmission provider to make an 

annual compliance filing and to propose 

in that filing a mechanism through 

which it will identify non-offending, 

transmission customers and a method 

by which it will distribute the 

unreserved use penalties revenue it 

receives to the identified transmission 

customers. This rule is consistent with 

our determination regarding the 

distribution of imbalance penalties. The 

transmission provider must also 

indicate in its compliance filing how it 

will distribute late study penalties to 

unaffiliated transmission customers. In 

addition, the transmission provider is 

required to make an annual filing with 

the Commission, described further 

below, that provides information 

regarding the penalty revenue the 

transmission provider has received and 

distributed. We will not allow the 

transmission provider to make an 

annual filing to propose a distribution 

method for unreserved use and late 

study penalties, as proposed in the 

NOPR. We agree with Ameren that 

restricting the transmission provider to 

proposing a distribution method 

through the transmission provider’s 

compliance filing will reduce the 

administrative burden of distributing 

operational penalties. We believe that 

we can accomplish the goals underlying 

a mandatory annual filing to propose a 

distribution method—to detect 

inappropriate penalties and failure to 

penalize the transmission provider’s 

affiliates—by requiring an annual 

informational filing. As suggested by 

Seattle, compliance monitoring and 

enforcement by Commission staff will 

provide a measure of assurance that the 

transmission provider appropriately 

assesses penalties. 

862. All point-to-point and network 

transmission customers, including the 

transmission provider’s native load, will 

be eligible to receive a portion of the 

penalty revenues distributed by the 

transmission provider. As a result, we 

will not adopt MidAmerican’s proposal 

that we exclude short-term firm and 

non-firm transmission customers to 

reduce the burden to the transmission 

provider. Given the steps we have taken 

to manage the transmission provider’s 

burden of distributing penalty revenues, 

we believe it more equitable to allow all 

transmission customers subject to 

operational penalties to be eligible to 

receive a portion of the distributed 

penalty revenues. In response to TVA’s 

suggestion that the amount of any such 

operational penalties be credited against 


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532E.g., ISO New England, PJM, MISO, SPP, and 

Ameren. 

533 In Order No. 888, the Commission stated that 

system expansions should be priced at the higher 

of the embedded cost rate (including the expansion 

costs) or the incremental cost rate, consistent with 

the Transmission Pricing Policy Statement. See 

Inquiry Concerning the Commission’s Pricing Policy 

for Transmission Services Provided by Public 

Utilities Under the Federal Power Act, Policy 

Statement, 59 FR 55031 at 55037 (Nov. 3, 1994), 

FERC Stats. & Regs. ¶ 31,005 at 31,146 (1994), order 

on reconsideration, 71 FERC ¶ 61,195 (1995) 

(Transmission Pricing Policy Statement). 

534Southwest Power Pool, Inc., 100 FERC 

¶ 61,096 (2002) (designing a rate to include a 

balloon payment is not a substitute for a properly 

designed rate). 

535Southwest Power Pool, Inc., 112 FERC 

¶ 61,319 at P 33 (2005). 

536See Southwest Power Pool, Inc., 98 FERC 

¶ 61,256 at 62,026, reh’g denied in pertinent part, 

the transmission provider’s 

transmission revenue requirement, we 

note that the transmission provider is 

free to propose this mechanism, with 

assurances that offending customers 

will not benefit, and we will decide the 

appropriateness of the proposal on a 

case-by-case basis. 

863. We agree with those commenters 

that assert that the transmission 

provider must be made whole before it 

distributes any penalty revenues. With 

regard to unreserved use penalties, we 

will allow the transmission provider to 

retain the base firm point-to-point 

transmission service charge, but require 

it to distribute any revenue collected 

above the base firm point-to-point 

transmission service charge. For 

instance, if a transmission customer has 

unreserved use that results in a penalty 

equal to twice the rate for firm weekly 

point-to-point service, then the 

transmission provider can retain an 

amount equal to the rate for firm weekly 

point-to-point transmissions service. A 

transmission provider will be required 

to distribute the entire amount it pays 

for completing service request studies 

on an untimely basis. 

864. We will not require transmission 

providers that make an annual 

compliance filing to use a standard 

template, as suggested by Nevada 

Companies. Transmission providers are 

in the best position to determine the 

least burdensome way to present the 

information required. We will provide 

guidance, however, on the information 

that transmission providers must 

provide in their annual informational 

filings. Transmission providers must 

provide: (1) A summary of penalty 

revenue credits by transmission 

customer, (2) total penalty revenues 

collected from affiliates, (3) total penalty 

revenues collected from non-affiliates, 

(4) a description of the costs incurred as 

a result of the offending behavior, and 

(5) a summary of the portion of the 

unreserved penalty revenue retained by 

the transmission provider. 

865. Transmission providers are 

prohibited from recovering for 

ratemaking purposes or through any 

service under the Commission’s 

jurisdiction any amount it or an affiliate 

pays as an operational penalty. This will 

ensure that the transmission provider 

faces a true financial consequence when 

it or an affiliate incurs an operational 

penalty. 

c. Applicability of Operational Penalties 

Proposal to RTOs and Other 

Independent or Non-Profit Entities 

866. The Commission did not address 

the degree to which RTOs and other 

independent entities would be subject 

to operational penalties in section V.C.4 

(Operational Penalties) of the NOPR. For 

the most part, the discussion in that 

section of the final rule addressed how 

a transmission provider should 

distribute operational penalties it incurs 

when it takes transmission service 

under its own tariff. In the section V.D.5 

(Acquisition of Transmission Service) of 

the NOPR, the Commission separately 

addressed whether RTOs should pay 

operational penalties for failure to 

complete request studies on a timely 

basis. 

Comments 

867. Several RTOs and RTO members 

asked that the Commission clarify that 

RTOs are not subject to any operational 

penalties.532 Entergy opposes the 

Commission’s proposal to assess 

operational penalties against non-RTO 

transmission providers, but not RTOs. 

However, if the Commission maintains 

this distinction, Entergy asks that it 

clarify that independent entities—such 

as Entergy’s Independent Coordinator of 

Transmission—and the transmission 

providers that allow independent 

entities to process transmission service 

requests will have the same protection 

from operational penalties as RTOs. PGP 

argues that, in the case of non-profit 

transmission providers, requiring the 

transmission provider to pay ‘‘nonoffending’’ customers when the provider 

incurs operational penalties is selfdefeating, because there is no one other 

than the customers to bear the cost of 

the penalty. PGP cites Bonneville as an 

example and notes that Bonneville must 

recover all costs from its customers. 

Commission Determination 

868. This section of the Final Rule 

primarily addresses how transmission 

providers should distribute operational 

penalties they incur when taking 

transmission service under their own 

tariff. RTOs and independent 

transmission coordinators do not take 

transmission service, so most of the 

discussion in this section of the Final 

Rule is simply not applicable to either 

RTOs or independent transmission 

coordinators. RTOs and independent 

transmission coordinators are bound 

however by the requirement to 

distribute revenues they receive when 

they assess operational penalties. We 

address whether RTOs or independent 

transmission coordinators are subject to 

operational penalties due to processing 

transmission service request studies on 

an untimely basis in section V.C.5.a of 

this Final Rule. We address whether 

RTOs are subject to civil penalties in 

section 0 of this Final Rule. 

869. We do not agree with those 

arguing that a non-profit transmission 

provider should be exempt from the 

requirement to distribute unreserved 

use penalties it pays when taking 

service under its own tariff. To the 

extent that a not-for-profit transmission 

provider incurs an operational penalty 

as a result of its activities as a 

transmission customer, it is still 

required to distribute penalties to nonoffending customers. A non-profit 

transmission provider would only incur 

an operational penalty as the result of 

its wholesale marketing operations. As 

such, a non-profit transmission provider 

would pay for any operational penalty 

it incurs by using the profit it has 

earned through its wholesale marketing 

operations. 

6. ‘‘Higher of’’ Pricing Policy 

870. As noted in the NOPR, the 

Commission is concerned that some 

transmission providers may not be 

applying our existing pricing policies 

consistently and, as a result, customers 

may be quoted prices that are not 

consistent with the ‘‘higher of’’

policy.533 The practice of quoting 

customers an incremental rate as a lump 

sum payment is inconsistent with our 

ratemaking policy and has the potential 

to discourage customers from 

proceeding with service requests.534

Under the Commission’s ‘‘higher of’’

pricing policy, when the requested 

transmission service requires network 

upgrades, the transmission provider 

should calculate a monthly incremental 

cost transmission rate using the revenue 

requirement associated with the 

required upgrades and compare this to 

the monthly embedded cost 

transmission rate, including the 

expansion costs.535 This incremental 

rate should be established by amortizing 

the cost of the upgrades over the life of 

the contract.536


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100 FERC ¶ 61,096 (2002) (‘‘We agree with SPP that 

the amortization period for upgrade costs should 

match the contract period * * * As the customer 

is only obligated to take service for the term of the 

contract, it is reasonable that the costs only be 

amortized over the term of the contract.’’). 

537E.g., APPA, Bonneville, and Public Power 

Council. 

538 E.g., ELCON, Constellation, FirstEnergy, 

NorthWestern, PGP, TDU Systems. 

539See NOPR at P 285 (‘‘Presenting the 

incremental charge in the form of a monthly rate 

allows a customer seeking a lower rate to choose to 

request a longer transaction term.’’). 

540Citing Midwest Indep. Transmission Sys. 

Operator, Inc., 109 FERC ¶ 61,085, P 57 (2004) 

(applying Order 2003 crediting mechanism to 

network customers). 

NOPR Proposal 

871. As a result of the Commission’s 

concerns regarding application of the 

‘‘higher of’’ pricing policy, the 

Commission sought comments in the 

NOPR on whether changes to the pro 

forma OATT are necessary to ensure 

that incremental cost transmission rates 

are presented as monthly rates for 

service. 

Comments 

872. Several commenters agree that 

incremental cost rates must be 

expressed as monthly rates, but do not 

believe that imposing this requirement 

requires changes to the pro forma 

OATT.537 To ensure transparency, 

Bonneville recommends that 

transmission providers post on their 

OASIS the methodology used to 

calculate incremental rates. APPA 

suggests that the Commission simply 

state in the preamble to the Final Rule 

that the transmission provider must 

include a proposed incremental rate in 

its offer of service. 

873. Other commenters see no need 

for clarification at this time. Southern 

states that it is not aware of problems 

regarding the calculation of incremental 

rates. Southern requests that the 

Commission consider allowing 

deviations to the Commission’s ‘‘higher 

of’’ pricing policies and to allow all 

transmission providers, not just RTOs, 

to utilize participant funding. 

MidAmerican suggests the Commission 

defer consideration of possible changes 

to the pro forma OATT regarding this 

issue until the Commission undertakes 

comprehensive transmission pricing 

reform. 

874. Other commenters support 

changes to the pro forma OATT that 

will ensure that incremental costs are 

presented as monthly rates for 

service.538 EPSA suggests that the Final 

Rule include an example of an 

appropriate monthly revenue 

requirement calculation and the 

upgrade costs included in the monthly 

rate. Suez Energy NA supports this 

proposed change but requests that the 

transmission provider be required to 

provide in a clear format the existing 

transmission rate, the lump sum cost of 

the upgrades, and the incremental rate. 

875. Some commenters ask the 

Commission to further clarify, or 

establish additional requirements, 

regarding incremental rates. Entegra 

states that the incremental rate should 

be stated as both a monthly unit rate 

and a lump sum representing the net 

present value of the upgrade costs with 

all inputs and assumptions in the 

calculation disclosed. Entegra further 

contends that the customer should be 

allowed to choose between paying the 

incremental rate, the lump sum, or some 

combination of the two (e.g., to pay an 

incremental rate over some period of 

time and then to pay the balance of the 

upgrade costs as a lump sum). While 

Morgan Stanley supports the 

Commission’s clarification that the 

transmission provider may not demand 

a lump sum payment as a condition of 

providing the requested service, it asks 

that transmission providers not be 

precluded from offering a lump sum 

payment option, or any other mutually 

agreeable approach, to customers. 

876. MidAmerican, EEI and 

Allegheny recommend that the 

Commission clarify that the 

transmission provider is not currently 

limited to charging the customer the rate 

per MW-month specified in the facilities 

study for the entire term of service if the 

customer pays the incremental cost of 

the network upgrades. These 

commenters explain that the 

transmission provider’s revenue 

requirement with respect to the 

incremental cost of network upgrades 

will vary over the customer’s term of 

service in the same way as its embedded 

cost of service will vary, including the 

cost of capital, operations and 

maintenance expense and 

administrative and general expense. EEI 

argues that the transmission provider 

should have the same right to modify a 

rate based on incremental costs 

pursuant to section 205 that it has to 

modify embedded cost rates and that the 

transmission provider should be 

permitted to present an incremental cost 

rate as a formula rate. 

877. Seattle states that incremental 

costs may require more rigorous 

treatment than simply stating a monthly 

rate, since the cost of expansion is very 

path specific and often the expansion 

will affect multiple beneficiaries. 

According to Seattle, the ‘‘higher of’’

pricing policy will often hinge on 

contestable assumptions regarding the 

beneficiaries of discrete expansion 

projects and the grey area that separates 

reliability related aspects of new 

transmission projects from projects 

intended to provide commercial 

benefits. 

878. Great Northern requests that the 

Commission clarify that a transmission 

customer may adjust the term of its 

requested transmission service contract 

to provide a longer period for 

amortizing the cost of necessary system 

upgrades once the incremental cost of 

expansion is disclosed by the 

transmission provider, as the 

Commission seems to suggest in the 

NOPR.539 In contrast, Allegheny states 

that the amortization period for the cost 

of an upgrade should not exceed the 

requested term of the contract, even if 

exercise of the rollover option by the 

customer is anticipated because 

transmission providers must have 

assurances of cost recovery for upgrades 

necessitated by customer decisions. 

879. TAPS and EEI recommend that 

the Commission modify sections 19.3 

and 19.4 of the pro forma OATT to 

specify that the transmission provider 

must present the incremental costs of 

transmission service on a $/MW month 

basis contemporaneous with providing 

the facilities study to the customer. 

TAPS further states that similar changes 

should be made to sections 32.3 and 

32.4 of the pro forma OATT, to ensure 

that network customers are not scared 

off by inappropriate presentations of 

network upgrade costs. TAPS explains 

that, while more complex, it believes 

that ‘‘higher of’’ pricing can work in the 

context of network service if applied in 

a comparable manner to the 

transmission provider’s treatment of the 

upgrades needed for service to its retail 

native load.540

880. ISO New England and PJM state 

that the Commission’s pricing concerns 

are not present for their respective 

markets and, therefore, any rule 

promulgated in this proceeding should 

not apply to these RTOs. 

881. TAPS argues that 

creditworthiness or security 

requirements associated with network 

upgrades for a transmission customer 

(in sections 19.4 and 32.4 of the pro 

forma OATT) must be distinguished 

from the incremental cost or pricing of 

the upgrade. Otherwise, the customer 

may mistake a demand for security for 

a request for upfront payment of the 

entire cost of the upgrade. 

882. In reply comments, EEI states 

that it continues to support the 

Commission’s proposed modification to 

the way in which the transmission 


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541Comments that fall into this category include 

those of Entegra, Suez Energy NA, Morgan Stanley, 

MidAmerican, EEI (regarding the right to modify 

incremental rates) and Allegheny. 

542Because the Commission declines to adopt 

changes to the pro forma OATT regarding the 

‘‘higher of’’ pricing policy, the requests of ISO New 

England and PJM to exempt ISOs and RTOs from 

tariff changes related to that policy are moot. 

Procedures regarding implementation of the Final 

Rule by ISOs and RTOs are otherwise discussed in 

section IV.C. 

543 In the Demand Response Report, staff 

recommended that federal and state regulators 

consider whether to allow appropriately designed 

demand response resources to provide all ancillary 

services including spinning reserve, regulation, and 

any new frequency responsive reserves. Demand 

Response Report at 97–100. 

544Section 1252 (f) of EPAct 2005 states: ‘‘It is the 

policy of the United States that time-based pricing 

and other forms of demand response, whereby 

electricity customers are provided with electricity 

price signals and the ability to benefit by 

responding to them, shall be encouraged, the 

deployment of such technology and devices that 

enable electricity customers to participate in such 

pricing and demand response systems shall be 

facilitated, and unnecessary barriers to demand 

response participation in energy, capacity and 

ancillary service markets shall be eliminated.’’

provider presents information on the 

incremental cost of network upgrades 

and asserts that nothing in the initial 

comments justifies a change in the 

Commission’s policies with respect to 

the pricing of transmission service. EEI 

states that changes in transmission 

pricing policy, such as NRECA’s 

proposal to require rolled-in pricing for 

network customers and TAPS’s proposal 

to exempt network customers from 

security for the payment of costs related 

to network upgrades, are outside the 

scope of this proceeding. 

Commission Determination 

883. In the NOPR, the Commission 

sought comments on the narrow issue of 

whether changes to the pro forma OATT 

are necessary to ensure that, consistent 

with our ‘‘higher of’’ policy, incremental 

cost transmission rates are presented as 

monthly rates for service. The 

Commission did not propose any 

changes to the underlying pricing 

policy. Commenters’ proposals to 

change or clarify the Commission’s 

transmission pricing policy are therefore 

outside the scope of this proceeding.541

Other comments are directed toward the 

application of our ‘‘higher of’’ policy in 

individual cases. These include the 

comments of Seattle (on the need to 

accurately identify the beneficiaries of 

the network upgrades), TAPS (on the 

use of ‘‘higher of’’ pricing in the context 

of network service), and EPSA (asking 

the Commission to present an example 

calculation of costs and rates). We will 

not address those comments here 

because they involve issues that are 

largely fact-specific that are best 

addressed on a case-by-case basis. 

884. Based on the remaining 

comments received, the Commission 

concludes that changes to the language 

of the pro forma OATT to address this 

matter are not needed at this time. We 

believe that the existing pricing policy 

provides sufficient information for 

transmission customers to make an 

informed decision regarding a request 

for service.542 Transmission providers 

must continue to include a proposed 

monthly incremental rate with their 

offer of service whenever the 

transmission provider proposes to 

charge the customer an incremental rate, 

as well as cost support indicating the 

derivation of the rate calculation 

consistent with the cost support that the 

transmission provider would provide to 

the Commission in a section 205 rate 

filing. Because transmission providers 

are required to explain the calculation 

of their incremental rate, we conclude 

that the transmission provider need not 

post on its OASIS the calculation 

methodology, as recommended by 

Bonneville. Similarly, in response to 

TAPS’s concern about security 

payments, the transmission provider’s 

explanation should allow the customer 

to clearly distinguish between any 

security requirements associated with 

the service and the incremental cost of 

the service. 

885. We will not adopt Great 

Northern’s recommendation to require 

the transmission provider to permit the 

customer to opt for a longer contract 

term (to obtain a longer amortization 

period and a lower rate) once the 

incremental cost of the upgrades has 

been determined. The specific upgrades 

required to provide transmission service 

may depend on the time period over 

which the service is provided; therefore, 

allowing the customer to opt for a longer 

contract term may trigger a need for 

additional, or different, upgrades. 

7. Other Ancillary Services 

886. Other than the pricing of 

imbalances, the NOPR did not address 

pricing issues related to ancillary 

services required under the pro forma 

OATT. A few commenters nonetheless 

proposed revisions to the pro forma 

OATT regarding the pricing and 

procurement of, and other issues related 

to, ancillary services. 

a. Demand Response 

Comments 

887. Alcoa submits that load 

resources (i.e., demand response) 

should be permitted to self-supply and, 

under certain circumstances, sell 

ancillary services to third parties. Alcoa 

states that large customers such as 

aluminum smelters are capable of 

providing, for themselves and third 

parties, some ancillary services so long 

as they are not required to subrogate 

their aluminum business functions to 

the needs of the ancillary service 

markets. In Alcoa’s view, demand 

resources such as Alcoa’s smelter loads 

should be appropriately compensated as 

providers of ancillary services, 

recognizing their ability to contribute 

significantly to the operational 

flexibility of energy markets and the 

stability of the grid. Alcoa asserts that 

industrial loads’ contribution to the 

reliability of the grid was demonstrated 

during the August 2003 Blackout, when 

Alcoa’s smelters remained in operation 

and facilitated the restoration of the 

system. Accordingly, Alcoa asks the 

Commission to require transmission 

providers to recognize that demand 

response resources can be a substitute 

for ancillary services such as Energy 

Imbalance, Operating Reserve and 

Spinning Reserve. 

Commission Determination 

888. With respect to Alcoa’s concern 

regarding a transmission customer’s 

own use of ancillary service, we note 

that the existing pro forma OATT 

requires transmission providers to 

permit transmission customers to 

purchase ancillary services from third 

parties or make alternative comparable 

arrangements for the provision of all 

ancillary services except for scheduling, 

system control and dispatch service and 

reactive supply and voltage control 

service. Regarding the sale of other 

ancillary services including energy 

imbalance, operating reserve and 

spinning reserve by load resources, we 

agree that such sales should be 

permitted where appropriate on a 

comparable basis to service provided by 

generation resources. Comparable 

treatment of load resources is consistent 

with Staff’s August 2006 Assessment of 

Demand Response & Advanced 

Metering Report 543 as well as 

provisions of EPAct 2005.544 We note 

that some RTOs and ISOs already allow 

demand response resources to 

participate in certain ancillary services 

markets, while participation of such 

resources in other ancillary services 

markets is being studied. We therefore 

modify Schedules 2, 3, 4, 5, 6, and 9 of 

the pro forma OATT to indicate that 

Reactive Supply and Voltage Control, 

Regulation and Frequency Response, 

Energy Imbalance, Spinning Reserves, 

Supplemental Reserves and Generator 

Imbalance Services, respectively, may 

be provided by generating units as well 


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545We note, however, that the rates charged for 

these ancillary services must be just and reasonable 

under the Commissions standard of review. Thus, 

if less expensive options to supply ancillary 

services (including from demand side resources) are 

available, we would expect the transmission 

provider to examine such options. 

546E.g., SPP, Alcoa, and Occidental. 547See Order No. 2003–A at P 416. 

as other non-generation resources such 

as demand resources where appropriate. 

b. Procurement and Pricing of Ancillary 

Services Generally 

Comments 

889. Steel Manufacturers Association 

contends that the pro forma OATT’s 

approach to other generation-based 

ancillary services should recognize that 

regional ancillary services markets do a 

better job of ensuring system reliability 

and holding down ancillary services 

costs than ancillary services provided 

on a control area by control area basis. 

Steel Manufacturers Association cites to 

MISO and SPP reports that provide 

evidence that ancillary services 

provided across large geographical 

regions are more effective and 

economical than when those services 

are provided by single utilities. For 

example, Steel Manufacturers 

Association notes that the SPP report 

concluded that, if a single Area Control 

Error were used for SPP, energy used for 

regulation service could be reduced by 

approximately 30 percent. Steel 

Manufacturers Association contends 

that, although ancillary services markets 

in the organized markets have proven 

successful at ensuring reliability and at 

keeping ancillary services costs low and 

predictable, utilities outside of the RTO 

and ISO markets continue to provide 

ancillary services primarily from their 

own limited pools of generation 

resources. 

890. Occidental and Steel 

Manufacturers Association propose that 

transmission providers should be 

required, if feasible, to competitively 

procure ancillary service products if 

there are suppliers of such services 

other than the vertically integrated 

merchant function. Occidental argues 

that such procurement will result in just 

and reasonable rates for these 

generation-related ancillary services that 

reflect their cost-effective market-based 

competitive supply. In Occidental’s 

view, competitive procurement of 

ancillary services will also help assure 

non-discriminatory treatment of 

transmission customers since 

transmission providers will have less 

incentive to favor their merchant 

function in the provision of generationrelated ancillary services. Occidental 

notes that such procurement should be 

conducted in a manner consistent with 

reliability. 

891. Alcoa argues that the 

transmission provider’s costs of 

providing ancillary services for the 

network as a whole should not be 

socialized on a MWh basis without 

regard to the relative cost burden that 

specific customers impose on the 

transmission system. Alcoa contends 

that, while a particular consumer may 

use a considerable quantity of energy, 

the cost of serving that customer beyond 

the per-unit energy cost may be much 

less than it would be for other 

individual customers or groups of 

customers. 

Commission Determination 

892. The Commission recognizes that 

there can be possible economic and 

reliability benefits to larger geographic 

markets for ancillary services, as 

suggested by Steel Manufacturers 

Association. However, as stated in the 

NOPR and repeated above the purpose 

of this rulemaking is to strengthen the 

pro forma OATT to ensure that it 

achieves its original purpose—

remedying undue discrimination—not 

to create new market structures or, as 

proposed here, to modify existing 

market structures. We do not believe 

that altering the scope of the current 

ancillary services markets is needed to 

remedy undue discrimination at this 

time. 

893. Similarly, we conclude that a 

fundamental overhaul of the current 

procurement and pricing of ancillary 

services, as proposed by Occidental and 

Steel Manufacturers Association, is 

beyond the scope of this proceeding.545

The pro forma OATT already permits 

transmission customers to make 

alternative arrangements to satisfy 

certain of their ancillary services 

obligations. Therefore, transmission 

customers are free to seek out 

competitive providers for those 

ancillary services other than scheduling, 

system control and dispatch service and 

reactive supply and voltage control 

service from third party suppliers. We 

also find Alcoa’s contention that the 

transmission provider’s costs of 

providing ancillary services for the 

network as a whole should not be 

socialized on a MWh basis without 

regard to the relative cost burden that 

specific customers impose on the 

transmission system, to be beyond the 

scope of this Final Rule. 

c. Pricing and Procurement of Reactive 

Power 

Comments 

894. Several commenters 546 suggest 

that the Commission consider the need 

for reform of the methods of 

compensation for the provision of 

reactive power. 

895. Alcoa argues that ancillary 

services pricing should recognize the 

efficiency contributions made by load as 

a result of their demand response 

capabilities and the contribution that 

load located near generators makes to 

the provision of reactive power in 

particular. Alcoa states that the 

localized supply of reactive power near 

load centers can alleviate transmission 

constraints and allow cheaper real 

power to be delivered into a load center, 

as the provision of such reactive power 

increases the available flow for real 

power between two points. Alcoa argues 

that the pro forma OATT should 

recognize and credit the manner in 

which certain loads’ location and load 

profile allows for the provision of 

reactive power and contributes to real 

power transfer capability. 

896. Occidental objects to the existing 

requirement that transmission 

customers purchase reactive power 

service from the transmission provider, 

arguing that numerous independent 

generators provide reactive supply and 

voltage control to support transmission 

service in competitive wholesale 

markets. Occidental states that the 

Commission should formalize the policy 

of compensating generators on a 

comparable, non-discriminatory basis 

for several ancillary services, 

particularly providing reactive power 

capability, by requiring changes to the 

pro forma OATT to mirror the changes 

accepted by the Commission to the PJM 

and MISO tariffs. Occidental contends 

that amending the pro forma OATT to 

formalize this policy would be 

consistent with the FPA and achieving 

non-discriminatory access to 

transmission. Occidental notes that PJM 

and MISO amended their tariffs to 

provide equal compensation to affiliated 

and non-affiliated generators based on 

the generation owner’s monthly revenue 

requirement for reactive supply and 

voltage control as accepted by the 

Commission. Occidental also notes that, 

when addressing generator 

interconnection agreements in Order 

No. 2003–A, the Commission stated that 

‘‘if the Transmission Provider pays its 

own or its affiliated generators for 

reactive power within the established 

[power factor] range, it must also pay 

[the interconnecting, independent 

generator].’’ 547

897. SPP requests that the 

Commission reform its reactive power 

pricing methodology, which has grown 


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548Opinion No. 440, 88 FERC ¶ 61,141 (1999). 

549See Order No. 2003–B at P 119. 

550See Calpine Oneta Power, L.P., 116 FERC 

¶ 61,282 (2006). 

551See Staff Report: Principles of Efficient and 

Reliable Reactive Power Supply and Consumption 

(Docket No. AD05–1–000), available at http:// 

www.ferc.gov/EventCalendar/Files/ 

20050310144430–02–04–05-reactive-power.pdf. 

Staff noted that in many cases load response and 

load-side investment could reduce the need for 

reactive power capability in the system and that 

increasing reactive power at certain locations 

(usually near a load center) can sometimes alleviate 

transmission constraints and allow cheaper real 

power to be delivered into a load pocket. See id. 

at 4, 108. The report also noted that distributed 

generators have the same reactive power 

characteristics as large generators, with both 

producing dynamic reactive power, and that the 

amount of reactive power does not necessarily 

decrease when voltage decreases. Id. at 27. 

552 In Order No. 888, the Commission referred to 

planning redispatch as economic redispatch. Here 

we avoid the term economic redispatch because in 

the last ten years it has taken a different meaning 

in the industry and because we will no longer 

require that planning redispatch be capped at the 

cost of expansion. 

553See pro forma OATT section 13.5. 

554See pro forma OATT section 19.3. 

555See pro forma OATT sections 33.2–33.3. 

556Conditional firm point-to-point service 

(hereinafter conditional firm service) and planning 

redispatch point-to-point service (hereinafter 

planning redispatch service) are options available 

under long-term firm point-to-point service. 

out of AEP Serv. Corp.548 SPP contends 

that the Commission can reduce 

uncertainty and litigation surrounding 

the pricing of reactive power by acting 

generically in a rulemaking rather than 

causing the industry to litigate reactive 

power pricing issues on a case-by-case 

basis. SPP argues that, based on its 

studies, it does not expect to call upon 

IPPs to provide reactive power; and 

therefore, it should not be required to 

pay for reactive power. SPP questions 

whether paying all IPPs a reservation 

charge, regardless of any determination 

of need or of the location of the plant 

and the locational need for reactive 

power, provides the appropriate siting 

incentives. SPP contends that the 

Commission can reduce the uncertainty 

and litigation by acting generically 

rather than causing the industry to fully 

litigate these issues in numerous cases 

before various courts. In addition, SPP 

challenges whether the AEP pricing 

method for reactive power continues to 

be appropriate. SPP suggests the 

Commission consider alternative pricing 

options, such as: Tying compensation to 

the actual provision of reactive power; 

eliminating compensation for the 

ninety-five percent leading/lagging band 

contained in most interconnection 

agreements, as such costs may be 

considered as a cost of interconnection 

and included in the power sales price; 

or, allowing compensation only outside 

of the band or perhaps when a sale is 

displaced. 

Commission Determination 

898. In Order No. 2003 et al., the 

Commission found that interconnection 

customers must be treated comparably 

with the transmission provider and its 

affiliates in terms of reactive power 

compensation. The Commission 

required the transmission provider to 

pay interconnecting generators for 

providing reactive power within the 

specified range if the transmission 

provider so pays its own generators or 

those of its affiliates.549 Commenters 

seeking reform of the methods of 

compensation for the provision of 

reactive power have not demonstrated 

that such reforms are needed at this 

time to remedy undue discrimination or 

that the current compensation method 

does not provide a comparable result. 

Accordingly, we do not believe that 

acting generically on pricing reactive 

power is needed at this time and we 

will continue to resolve compensation 

issues for reactive power to qualifying 

generators on a case-by-case basis based 

on the circumstances presented. 

899. In response to SPP’s specific 

proposals for the treatment of reactive 

power, we note that the Commission 

recently found that it is unduly 

discriminatory and non-comparable for 

SPP to apply a ‘‘needs’’ test to reactive 

power capability for independent power 

producers to receive compensation that 

is not also applied to all other 

generating plants in its vicinity.550 The 

Commission also found that parties may 

make a separate FPA section 205 filing 

with the Commission with criteria, 

applied comparably and prospectively, 

that would determine which generators 

would receive reactive power 

compensation. 

900. Finally, Alcoa’s assertion that 

certain loads’ location and load profile 

allows for the provision of reactive 

power to the transmission system is 

consistent with Staff’s February 2005 

report, Principles for Efficient and 

Reliable Reactive Power Supply and 

Consumption,551 as well as the abovecited provisions of EPAct 2005. As 

previously discussed, we have modified 

Schedule 2 of the pro forma OATT to 

allow for the provision of Reactive 

Supply and Voltage Control from 

demand resources where appropriate. 

D. Non-Rate Terms and Conditions 

1. Modifications to Long-Term Firm 

Point-to-Point Service 

a. Planning Redispatch and Conditional 

Firm Options 

901. The current pro forma OATT 

requires the transmission provider to 

provide two types of redispatch service: 

Planning redispatch and reliability 

redispatch.552 Planning redispatch is a 

product that Order No. 888 required 

transmission providers to use, in certain 

circumstances, to create additional 

transmission capacity to accommodate a 

request for firm transmission service. 

Specifically, the existing pro forma 

OATT requires the transmission 

provider to expand or upgrade its 

transmission system or, if it is more 

economical, plan to redispatch its 

resources to provide requested firm 

point-to-point service, provided 

redispatch does not (1) degrade or 

impair the reliability of service to native 

load customers, network customers and 

other transmission customers taking 

firm point-to-point service or (2) 

interfere with the transmission 

provider’s ability to meet prior firm 

contractual commitments to others.553

The transmission provider must first 

identify planning redispatch options in 

the system impact study in conjunction 

with identifying relevant system 

constraints that impact the service 

request.554 When a system impact study 

and facilities study identify planning 

redispatch as a more economical means 

of relieving a transmission constraint 

than a transmission upgrade, the 

customer is obligated to pay the costs of 

redispatch consistent with Commission 

policy. 

902. Reliability redispatch is required, 

when feasible, to relieve system 

constraints that would otherwise cause 

curtailment of the network customer or 

transmission provider loads. To provide 

reliability redispatch, the transmission 

provider redispatches all network 

resources and transmission provider 

resources on a least-cost basis. The 

transmission provider and network 

customers each pay a load ratio share of 

these redispatch costs.555

NOPR Proposal 

903. In the NOPR, the Commission 

stated its belief that current practices for 

evaluating long-term firm point-to-point 

service may not be comparable to the 

manner in which transmission service is 

planned for bundled retail native load 

and may no longer be just, reasonable 

and not unduly discriminatory. The 

Commission described two potential 

solutions: modifications to the planning 

redispatch provisions and conditional 

firm point-to-point service.556 The 

Commission proposed to modify the 

existing planning redispatch option by 

(1) accelerating the study of planning 


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557The Commission did not propose to modify 

the reliability redispatch provisions that exist in the 

network integration transmission sections of the pro 

forma OATT. 558The following summary reflects comments 

received as initial and reply comments to the 

NOPR, as well as supplemental comments received 

in response to the November 15 Notice. Some 

commenters have changed their positions over time 

and these summaries reflect the most recent 

position expressed by commenters. 559Questions relating to the TDA proposal are 

discussed later in this section. 

560E.g., Exelon, FirstEnergy, ELCON, 

MidAmerican, Arkansas Commission, MISO, and 

East Texas Cooperatives. 

561E.g., EEI, Indianapolis Power, Ameren, and 

Northwest IOUs. 

562E.g., EPSA, AWEA, Entegra, BP Energy, 

Newmont Mining, Sempra Global, Suez Energy NA, 

PPM, Utah Municipals, Williams, Morgan Stanley, 

PPL, Project for Sustainable FERC Energy Policy, 

California Commission, CREPC, TranServ, South 

Carolina E&G, Constellation, Barrick Supplemental, 

Xcel Supplemental, and Bonneville Supplemental. 

563E.g., California Commission Supplemental, 

Williams Supplemental, Constellation 

Supplemental, and Barrick Supplemental. 

564E.g., Ameren, Duke, Entergy, Imperial, 

International Transmission, LPPC, Progress Energy, 

Santee Cooper, Salt River, Southern, Tacoma, TDU 

Systems, Community Power Alliance, Northwest 

IOUs, NorthWestern, NPPD, NRECA, Public Power 

Council, TVA, SPP Reply, South Carolina E&G 

Supplemental, E.ON Supplemental, MISO 

Supplemental, and APPA Supplemental. 

565E.g., Duke, EEI, LPPC, NRECA, NPPD, Progress 

Energy, Southern, Utah Municipals Reply, and 

Duke Reply. 

redispatch in the transmission request 

study process, (2) requiring an estimate 

of the number of hours of redispatch 

that may be required to accommodate 

the requested service, (3) requiring a 

preliminary estimate of the cost of 

planning redispatch, and (4) pricing 

planning redispatch services to facilitate 

increased availability of the service.557

The Commission suggested that 

conditional firm service could also be 

used to accommodate additional 

transactions, defining the service as a 

form of firm point-to-point service that 

includes less-than-firm service in a 

defined number of hours of the year 

when firm point-to-point service is 

unavailable. The Commission sought 

comment on its preliminary view that 

planning redispatch is the superior 

option because, in part, it is comparable 

to the way the transmission provider 

plans for bundled retail native load. 

904. The Commission’s October 12 

Technical Conference focused, among 

other things, on issues related to the 

planning redispatch and conditional 

firm proposals in the NOPR. On 

November 15, 2006, the Commission 

issued a notice (November 15 Notice) 

requesting supplemental comments on a 

transparent redispatch proposal 

submitted by Transparent Dispatch 

Advocates (TDA proposal) and certain 

aspects of the conditional firm 

option.558 The Commission also 

requested comments regarding the 

conditional firm option, including 

whether it is a complementary service to 

planning redispatch, whether it should 

be available for all long-term requests or 

limited to a request where the customer 

agrees to pay for upgrades, potential 

modeling problems, and requirements 

for defining the conditions under which 

the service would be curtailable.559

Comments 

905. Some commenters agree with the 

Commission’s preference for 

modifications to planning redispatch 

over development of conditional firm 

service.560 They state that the attributes 

of conditional firm service are not 

clearly defined and key implementation 

issues are unresolved. They state that 

using planning redispatch to the 

maximum degree feasible, while not 

interfering with reliability, is inherent 

in maximizing the efficient use of the 

transmission system and should be fully 

evaluated before undertaking expensive 

expansion of the transmission system. 

Other commenters state that conditional 

firm service will create significant 

complications for transmission 

providers and disincentives to build 

transmission in exchange for limited 

and questionable benefits for new pointto-point customers or LSEs.561 EEI, 

Indianapolis Power and Ameren express 

doubt that customers would agree to be 

curtailed during peak usage periods. In 

response, AWEA contends that existing 

resources serving load would be able to 

manage curtailment risks so long as they 

could reasonably predict the curtailed 

hours. 

906. Most independent power 

producers and a few other entities 

support the inclusion of both services in 

the pro forma OATT, stating that the 

services are required to remedy undue 

discrimination and provide for 

comparable transmission service.562

Western Governors believe that the 

planning redispatch and conditional 

firm options are important to fully use 

the existing transmission grid and to 

enable new intermittent generation 

resources to reach markets. To build the 

case for transmission expansion, the 

Western Governors argue, it is important 

to demonstrate that the existing grid is 

being effectively utilized; approval of 

both options will help make this 

necessary demonstration. EPSA and 

AWEA state that, while they believe 

transmission providers should be 

required to offer both services, 

conditional firm service may be simpler 

and less costly to implement because it 

involves the transmission provider 

directing the customer to turn off its 

resources during a contingency. 

Similarly, Bonneville suggests that 

conditional firm service is a reasonable 

alternative to planning redispatch where 

a transmission provider cannot provide 

both options. Commenters state that the 

Commission should require 

transmission providers to offer 

conditional firm service and planning 

redispatch and allow customers to 

choose the option that best suits the 

physical, commercial and economic 

circumstances of the request.563

907. On the other hand, many 

commenters argue that the Commission 

should not require either option because 

the services are unnecessary, 

operationally unworkable, and legally 

unjustified, or because they would harm 

reliability and the quality of existing 

network service and provide 

disincentives for transmission 

investment.564 Several commenters state 

that these services would make 

curtailments of existing firm service 

more likely and limit opportunities for 

use of secondary network service, 

thereby harming native load protections 

and reducing reliability, contrary to FPA 

sections 215 and 217 respectively.565

Others opposing both options put forth 

primarily reliability, cost causation and 

comparability arguments. For example, 

Duke states that the two options are 

antithetical to reliable grid operation 

because they would require a 

transmission provider to grant a longterm request with the prior knowledge 

that it cannot be accommodated. 

International Transmission states that 

the grid is already operating at capacity 

and that requiring the transmission 

provider to accommodate additional 

megawatt-hours of service during 

periods of system stress would increase 

the likelihood of system failure. While 

it recognizes that conditional firm 

service has been successful in parts of 

the Western Interconnection, NRECA 

contends a mandate would undermine 

responsible planning and expansion of 

the transmission grid by harnessing the 

transmission provider’s planning and 

dispatch functions to frame more and 

more elaborate service conditions for 

conditional firm service. APPA, 

Southern and Progress Energy argue that 

both services may require adoption of a 

form of organized LMP market, an 

action that raises significant political 

opposition and would be contrary to the 

Commission’s commitment in the NOPR 

to avoid such restructuring. Similarly, 

other commenters contend that the 

planning redispatch option is only 

appropriate for transmission providers 

who are members of an RTO, ISO or 


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566E.g., CREPC, TVA, and East Texas 

Cooperatives. 

567E.g., EEI, Entergy, Ameren, Progress Energy, 

Santee Cooper, TAPS, E.ON Supplemental, TDU 

Systems Supplemental, LPPC Supplemental, 

Tacoma Supplemental, and PNM–TNMP 

Supplemental. 

568E.g., Manitoba Hydro, Nevada Companies, 

Sacramento, Pinnacle, East Texas Cooperatives, 

Barrick Reply, APPA Supplemental, Community 

Power Alliance Supplemental, Entergy 

Supplemental, and TAPS Supplemental. 

569Section V.D.1.b contains a summary and indepth discussion of the TDA proposal. 

570The following entities expressed some level of 

support for conditional firm service: EPSA, AWEA, 

Entegra, BP Energy, Newmont Mining, Sempra 

Global, Suez Energy NA, PPM, Utah Municipals, 

Williams, Morgan Stanley, PPL, Project for 

Sustainable FERC Energy Policy, California 

Commission, Western Governors, CREPC, TranServ, 

Constellation, Manitoba Hydro, Nevada Companies, 

Sacramento, Pinnacle, PNM–TNMP, Bonneville, 

EEI, Entergy, Ameren, Progress Energy, Southern, 

Santee Cooper, Seattle, LPPC, Salt River, and TAPS. 

571E.g., EEI, Southern, TAPS, Seattle, APPA, 

LPPC Supplemental, Tacoma Supplemental and 

E.ON Supplemental. Issues related to pricing of 

planning redispatch service are addressed in 

paragraphs V.D.1.a.3.c below. 

572E.g., California Commission, PGP, Pinnacle, 

and Imperial. 

who have an independent administrator 

of their transmission system.566 Some of 

the commenters that urge rejection of 

both options state that a properly 

structured conditional firm service is 

preferable to the modified planning 

redispatch service should the 

Commission implement one of the 

services.567

908. Several commenters prefer the 

development of conditional firm service 

over the modifications to the planning 

redispatch service because of the 

complexities surrounding redispatch 

costs and protocols.568 For example, in 

supplemental comments, EEI and 

Community Power Alliance state that, 

while not ideal, conditional firm service 

would provide an opportunity to meet 

customers’ transmission needs and is 

preferable to Transparent Dispatch 

Advocates’ redispatch proposal.569 They 

also contend that the conditional firm 

option would provide faster provision of 

service and relative certainty of timing 

and costs for a new customer and its 

lenders, while ensuring reliability and 

promoting infrastructure expansion, so 

long as transmission providers are 

permitted to work with their customers 

to devise appropriate service 

parameters. Entergy believes conditional 

firm service can provide benefits to 

transmission customers without unfairly 

socializing costs to native load and 

network customers of the transmission 

provider. Overall, a majority of 

commenters express support for some 

form of conditional firm service.570

909. Several commenters argue that, if 

the services are required, the 

Commission should add to the services 

the following requirements: The 

services should not adversely affect 

reliability and service to firm customers 

or provide unduly preferential service to 

point-to-point customers; the services 

should be an interim option until 

transmission upgrades are in place to 

provide firm service; and, planning 

redispatch and conditional firm 

customers should bear the actual costs 

of the services received, including costs 

associated with system operational 

changes needed to accommodate the 

services.571

910. A few commenters believe that 

the Commission should allow for 

regional differences in development of 

the new services.572

Commission Determination 

911. The Commission has determined 

that modifications to the current 

planning redispatch requirement and 

creation of a conditional firm option are 

both necessary for provision of reliable 

and non-discriminatory point-to-point 

transmission service. The planning 

redispatch and conditional firm options 

represent different ways of addressing 

similar problems. They can be used to 

remedy a system condition that occurs 

infrequently and prevents the granting 

of a long-term firm point-to-point 

service. These options also can be used 

to provide service until transmission 

upgrades are completed to provide fully 

firm service. Planning redispatch 

involves an ex ante determination of 

whether out-of-merit order generation 

resources can be used to maintain firm 

service. Conditional firm involves an ex 

ante determination of whether there are 

limited conditions or hours under 

which firm service can be curtailed to 

allow firm service to be provided in all 

other conditions or hours. As we 

explain below, both techniques are 

currently used under certain conditions 

by transmission providers to serve 

native load and, hence, it is necessary 

to make comparable services available 

to transmission customers in order to 

avoid undue discrimination. 

912. We therefore find these options 

are complementary services that can 

remedy undue discrimination, facilitate 

the provision of long-term transmission 

service and provide customers with 

greater flexibility in choosing resources 

to meet their needs. There is support in 

the comments for development of some 

type of conditional firm service that 

would allow for a longer-term use of the 

grid when transmission is projected to 

be unavailable for a small portion of the 

year. Additionally, we note that both 

options could help integrate new 

generation more quickly. For example, 

when there is a lag between the time 

that a new generation resource becomes 

operational and the time that 

transmission upgrades can be built to 

accommodate the resource, these 

options allow power to reach customer 

loads at an earlier date. This can be 

particularly beneficial to renewable 

resources, such as wind, that can be 

constructed more quickly than the 

transmission upgrades necessary to 

deliver their power on a firm basis over 

the long-run. 

913. We recognize, however, that both 

options raise reliability concerns. The 

proposal in the NOPR for planning 

redispatch service would require the 

transmission provider to predict system 

conditions for the term of the service 

request, a task that becomes more 

difficult, and hence less accurate, with 

longer-term requests. This poses several 

related problems. Because longer-term 

forecasts are inherently uncertain and 

the further into the future the forecasts, 

the less accurate they are, the provision 

of planning redispatch service can 

threaten the reliability of service to 

native load unless very conservative 

assumptions are used. This incentive to 

use conservative assumptions to protect 

native load, in turn, increases the 

likelihood that planning redispatch 

service will be denied. This, in turn, 

will increase the number of disputes as 

to whether the denials were 

discriminatory. Such disputes would 

pose enforcement problems because 

they will turn on long-term projections 

regarding load growth, generation 

resource additions, etc., that by 

definition involve some degree of 

subjectivity. Moreover, as we discuss 

below, there is evidence suggesting that, 

while transmission providers use 

planning redispatch to serve native 

load, they do not use it as a long-term 

tool to avoid future upgrades 

indefinitely. 

914. In balancing the foregoing 

considerations, the Commission will 

modify the approach proposed in the 

NOPR in two principal respects. First, 

given the ability of both services to 

address similar problems, we have 

reconsidered the proposal that only one 

of the options should be required. We 

find that availability of both planning 

redispatch and conditional firm in the 

short-run is necessary to ensure that 

competitive power suppliers have 

comparable access to the grid. As 

discussed below, we will continue to 

require that transmission providers offer 

to provide planning redispatch under 

certain circumstances in which the 

transmission providers determine that 

there is insufficient ATC. If customers 


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573Application of planning redispatch and 

conditional firm service obligations to RTO and ISO 

transmission providers is discussed in section 

V.D.1.a.3.B.i below. 

574As explained in more detail below, we adopt 

limitations that are tailored to the two types of 

customers that may request the options. First, for 

customers that agree to support the construction of 

new transmission facilities, redispatch and 

conditional firm point-to-point service will be 

available as a bridge until such time as those 

facilities are constructed and the relevant 

conditions must be specified in the initial service 

agreement and are not subject to change. Second, 

for customers that do not agree to support the 

construction of new facilities, the transmission 

provider will be able to re-evaluate the conditions 

under which services are provided every two years. 

575The Commission did not propose to modify 

the reliability redispatch provisions that exist in the 

network integration transmission sections of the pro 

forma OATT. 

576E.g., EEI, TDU Systems, NRECA, Southern, 

and Duke Reply. 

577E.g., Southern, Duke, and Progress. Duke 

suggests that the Commission exempt transmission 

providers from the obligation to provide redispatch 

if they commit not to use redispatch as a planning 

tool for native load, network customers or merchant 

functions. 

578Southern states that it offered this service on 

a comparable basis to a non-affiliated transmission 

customer. 

579E.g., TDU Systems and EEI Reply. 

580E.g., LPPC, NPPD, Progress Energy, and Salt 

River. 

581E.g., AWEA, Utah Municipals, Project for 

Sustainable FERC Energy Policy, EPSA, and Barrick 

Reply citing NOPR at P 300. 

582EPSA Reply. 

request study of planning redispatch, 

transmission providers have an 

obligation to seriously evaluate the 

provision of planning redispatch from 

their own resources and provide 

customers with information on the 

capabilities of other generators to 

provide planning redispatch. If planning 

redispatch is unavailable from the 

transmission provider’s resources or 

inadequate to meet customers’ needs, 

transmission providers have an 

independent obligation to offer 

conditional firm, if available, as part of 

the firm point-to-point service.573

Customers will have the choice of 

whether to request study of the planning 

redispatch option, the conditional firm 

option or both. 

915. Second, we will not impose a 

planning redispatch or conditional firm 

obligation over the long run. Such an 

obligation is not, as described below, 

necessary to remedy undue 

discrimination and would otherwise 

pose reliability problems, put the 

transmission provider at risk for 

estimating the costs of long-term 

redispatch, and undermine incentives to 

upgrade the transmission grid. 

Therefore, we will limit the availability 

of both service options so that their 

duration is for a time period over which 

service can be reasonably provided 

without impairing reliability.574 This 

limitation scales back the existing 

planning redispatch requirement in 

section 13.5 of the pro forma OATT that 

could, in practice, allow for an openended obligation to provide planning 

redispatch in lieu of upgrading the 

transmission system (e.g., involving 

forecasts up to 30 years). 

916. We discuss in detail the 

comparability and reliability findings 

that support these decisions below. 

(1) Comparability 

NOPR Proposal 

917. In the NOPR, the Commission 

expressed its preliminary view that 

current practices for evaluating longterm firm point-to-point service may not 

be comparable to the manner in which 

transmission service is planned for 

bundled retail native load and may no 

longer be just, reasonable and not 

unduly discriminatory.575

Comments 

918. Some commenters challenge the 

Commission’s authority to order 

planning redispatch or conditional firm 

service as a remedy for potential undue 

discrimination. EEI and others argue 

that planning redispatch is not 

necessary to eliminate actual or 

perceived undue discrimination because 

many transmission providers do not rely 

on redispatch in planning to serve 

native load.576 However, EEI also states 

that when transmission providers do 

incorporate redispatch into their system 

planning, they do so generally only 

when the cost of redispatch is lower 

than the cost of network upgrades and 

system reliability is not impacted. Some 

transmission providers state that they 

do not currently use planning 

redispatch in lieu of transmission 

construction in order to designate their 

network resources.577 On the other 

hand, Entergy and Southern state that 

they currently use or have used 

planning redispatch of their own 

resources on the same basis that they 

allow any network customer to 

redispatch from the network customer’s 

resources. For example, Southern states 

that it has used the redispatch potential 

of its generators during off-peak/ 

shoulder periods on an interim basis 

until completion of transmission 

upgrades to designate network resources 

that otherwise might be 

undeliverable.578 Entergy disagrees that 

there is undue discrimination because 

this service is not available to point-topoint customers, stating that network 

and point-to-point service are not 

similarly situated services. TDU 

Systems state that conditional firm 

service does not ensure comparability 

among types of transmission service or 

between transmission providers and 

transmission customers. NRECA and 

others argue that the Commission 

requires a better understanding of the 

degree to which comparability is a 

problem in providing point-to-point 

service before the Commission makes 

changes to point-to-point service.579 In 

supplemental comments, EEI contends 

that the record in this proceeding does 

not demonstrate that conditional firm 

service is necessary to remedy undue 

discrimination. 

919. Others assert that it is not within 

the Commission’s jurisdiction to order 

planning redispatch for point-to-point 

customers because this type of 

redispatch requires use of the 

transmission provider’s generation 

resources.580 LPPC states that the 

comparability principle is wrongly 

applied to the use of generation by a 

transmission provider. In Salt River’s 

view, the Commission proposal sets up 

its own form of discrimination by 

making redispatch of the transmission 

provider’s resources mandatory while 

making redispatch of generation using 

firm point-to-point reservations and 

generation in other control areas 

voluntary. 

920. Those that support development 

of both services support the 

Commission’s statement in the NOPR 

that ‘‘transmission owners may evaluate 

transmission availability to serve longterm transmission service requests in a 

manner that is not comparable with the 

method they use to evaluate 

transmission needs for bundled retail 

native load.’’ 581 They argue that this 

divergent treatment of internal 

transmission needs versus external 

transmission requests is unduly 

discriminatory and violates the FPA. 

EPSA states that the fact that point-topoint service requests can be rejected 

due to a few hours of predicted 

reliability problems in a year is 

‘‘evidence of a poor use of existing 

transmission capacity and display clear 

discrimination against non-affiliated 

generation and its customers.’’ 582

TransAlta states that its actual 

experience with planning redispatch in 

the Pacific Northwest demonstrates that 

planning redispatch is used 

discriminatorily to the benefit of some 

customers and the detriment of others. 

921. In support of conditional firm 

service, Manitoba Hydro and Tacoma 

reiterate their experience that long-term 

transmission service requests are being 

denied due to constraints occurring 

during a small percentage of the time 

within the requested period of service. 


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583E.g., EPSA, AWEA, and Project for Sustainable 

FERC Energy Policy. 

584See pro forma OATT section 19.3. 

585See pro forma OATT section 13.5. 

586Entergy and Southern. EEI’s comments also 

indicate that at least a few transmission providers 

do rely on redispatch in planning to serve their 

native loads. 

587SPS, also known as remedial action schemes, 

are used to varying degrees in every NERC 

reliability region. For example, there are about 65 

SPS in the Western Interconnection. See Western 

Electricity Coordinating Council Operating 

Procedures, Index, V–1 to V–5 (revised July 2, 

2002). There are 8 SPS used by Florida Power and 

Light in FRCC. See Florida Power and Light Control 

Area Readiness Audit Report, 19 (March 10–11, 

2004). Two SPS are used in the Southern Subregion 

of SERC. Reliability Coordinator Readiness Audit 

Report Southern Subregion Reliability Coordinator, 

19 (March 27–30, 2006). 

EPSA and AWEA similarly state that a 

transmission provider will reject a longterm firm service request unless it can 

satisfy every element of the request. 

Manitoba Hydro and others state that, in 

an era of transmission underinvestment, optimizing the capacity 

usage is paramount to system 

reliability.583 EPSA and AWEA further 

explain that the concept of turning off 

a generator to avoid system upgrades is 

not new; Maine Independence Station 

avoided expensive system upgrades by 

installing automatic switching devices 

to take it offline during certain system 

conditions. Seattle states that, according 

to the Seams Steering Committee of the 

Western Interconnection, utilization on 

most constrained paths is limited to 

only a few hundred hours per year and, 

therefore, it is highly likely that service 

under a conditional firm product could 

be offered for even a baseload plant 

without significantly impacting the 

capacity factor. Santee Cooper states 

that, unlike the planning redispatch 

option, conditional firm service is 

presumptively within the subject matter 

jurisdiction of the Commission. 

922. Entergy states that the most 

comparable service for long-term pointto-point transmission customers is not a 

requirement that a transmission 

provider redispatch its own or network 

customers’ resources to grant long-term 

firm point-to-point transmission service. 

The most comparable service instead is 

a service that allows the transmission 

provider to curtail the service granted, 

while permitting the point-to-point 

customer to obtain alternative, 

deliverable resources if and when such 

curtailments occur in real-time. 

Commission Determination 

923. We reject arguments that 

planning redispatch service is 

unnecessary to remedy undue 

discrimination as a collateral attack on 

Order No. 888. The obligation to 

provide planning redispatch was 

established in Order No. 888. The 

modifications proposed in the NOPR 

did not increase the obligation placed 

on transmission providers to use their 

generation resources to provide 

planning redispatch to point-to-point 

customers. Rather, the proposed 

modifications merely added specificity 

to the redispatch information already 

required in a system impact study and 

adjusted the timing of when the 

transmission provider must study 

planning redispatch options.584

Therefore, many of the arguments 

raised, including arguments pertaining 

to the Commission’s jurisdiction over 

transmission provider generation 

resources, are impermissible collateral 

attacks on the current planning 

redispatch obligation in Order No. 888. 

Entergy’s argument that planning 

redispatch should not be available to 

point-to-point customers because they 

are not similarly situated to be able to 

provide redispatch from their own units 

thus ignores the current obligation for 

each transmission provider to provide 

redispatch from the transmission 

provider’s resources, if available, in 

evaluating a request for long-term pointto-point service.585

924. Additionally, information in the 

comments counters the assertion that 

transmission providers do not use 

planning redispatch or service 

analogous to the conditional firm option 

for their own loads. Entergy and 

Southern volunteer that they have 

planned for redispatch of their own 

resources in order to designate network 

resources when ATC was 

unavailable.586 As a caveat, Southern 

states that it has planned for the use of 

redispatch only for an interim period 

until upgrades could be constructed to 

make the transmission service from the 

designated resource fully firm. Entergy 

states that it offers planning redispatch 

service to network customers that plan 

to use their own resources to provide 

redispatch in real time. Contrary to EEI’s 

assertion about the record in this 

proceeding, commenters, such as EPSA 

and AWEA, explain that some 

transmission providers already employ 

automatic devices, such as special 

protection systems (SPS), to take 

resources offline during certain system 

conditions. In a way that is analogous to 

the proposed conditional firm service, 

these protection schemes are used to 

increase native loads’ firm uses of the 

transmission system until a contingency 

occurs that reduces available 

transmission.587 This information, taken 

together, provides ample evidence to 

support our finding that transmission 

providers currently evaluate 

transmission availability to serve longterm firm point-to-point transmission 

service requests in a manner that is not 

comparable with the method they use to 

evaluate their own transmission needs 

and to integrate their resources to serve 

bundled retail native load. 

925. Furthermore, we wish to 

emphasize that, in making these 

findings in support of a conditional firm 

option, we are not relying on the 

findings to create a new service. This 

Final Rule retains the two services 

adopted in Order No. 888—point-topoint service and network service. 

Conditional firm service is not a third 

service, but rather represents a 

modification to the existing procedures 

for granting long-term point-to-point 

service and the curtailment priorities for 

that service. The primary purpose of 

conditional firm is to address the ‘‘all or 

nothing’’ problem associated with the 

current procedures for requesting longterm point-to-point service. Currently, a 

request can be denied because firm 

service is unavailable in a very few 

hours of the year. For a customer who 

needs long-term point-to-point service 

to support a long-term transaction, this 

leaves the customer in the position of 

trying to cobble together a collection of 

shorter-term requests to effectuate its 

transaction, e.g., arranging firm service 

in the periods when it is available and 

non-firm service in the other periods. 

Such a customer also risks interruption 

of the non-firm portion of its service for 

economic reasons, e.g., a day of nonfirm service for the customer combining 

firm and non-firm service could be 

interrupted for another customer 

seeking one month of non-firm service. 

We do not believe such an approach is 

just and reasonable. It makes little sense 

to ask the customer to cobble together a 

collection of firm and non-firm requests 

when the transmission provider has 

better information about when the 

service may be available or unavailable. 

It is therefore appropriate to require the 

transmission provider to grant the 

service on a conditional basis, as we 

explain further below. 

926. We are however modifying the 

planning redispatch obligation, and 

similarly limiting the conditional firm 

option, to better reflect the manner in 

which redispatch or special protections 

schemes are used by transmission 

providers, in recognition of certain 

legitimate reliability concerns and the 

inherent difficulty of long-term 

projections in this area. This Final Rule 

limits transmission providers’ planning 

redispatch obligations by removing the 

current obligation to provide planning 

redispatch for an indefinite period as 


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588See supra section V.D.5.b. 

589E.g., Duke, Entergy, WAPA, NRECA, NPPD, 

LPPC, and Southern. 

590E.g., EEI, Indianapolis Power, Public Power 

Council, Southern, Seattle, Sacramento, and LPPC. 

long as the redispatch is cheaper than 

the relevant transmission upgrades. We 

also limit the conditional firm option by 

linking it to the transmission upgrades 

or a biennial assessment of the 

conditions. 

927. We find such an open-ended 

obligation to provide this service is not 

necessary to remedy undue 

discrimination, nor is it consistent with 

the need to maintain system reliability. 

As indicated above, transmission 

providers temporally limit their use of 

planning redispatch and curtailment of 

resources and there is no evidence that 

transmission providers use these 

options on a prolonged basis, e.g., for 

more than a few years, without 

upgrading their transmission systems. 

Rather, over the long run, transmission 

providers generally will construct 

sufficient transmission to integrate their 

resources on a firm basis. This is 

consistent with transmission planning 

requirements and the emphasis placed 

upon transmission expansion in this 

Final Rule. The modifications to longterm point-to-point service we adopt are 

consistent and comparable to the 

existing use of these options by 

transmission providers’ bundled retail 

native loads. Thus, the planning 

redispatch and conditional firm options 

will be available primarily as interim 

measures until transmission systems are 

upgraded to meet the transmission 

service request. We believe this 

limitation will have the added benefit of 

lessening disincentives to provide the 

service so that more planning redispatch 

is offered to transmission customers by 

transmission providers. 

928. We disagree with TDU Systems’

statement that conditional firm service 

does not ensure comparability among 

types of transmission service or between 

transmission providers and 

transmission customers. TDU Systems’

assertion is unsupported by any 

explanation or examples of how the 

conditional firm service would degrade 

comparability. Nevertheless, we believe 

the argument is essentially a collateral 

attack on Order No. 888. Order No. 888, 

not this rulemaking, created the 

distinction between point-to-point 

transmission service and network 

integration service. We did so to 

recognize the different ways in which 

transmission providers typically use 

their system. The two services are not 

precisely the same, nor were they intend 

to be identical. Nothing in this Final 

Rule changes these distinctions. Indeed, 

we are not changing the relative 

priorities applicable to firm point-topoint service, network integration 

service and service to bundled native 

load.588 These services do, and will 

continue to, share the same priority—

the highest priority of firm service on 

the transmission provider’s system. The 

only change, as it relates to the 

conditional firm option, is to allow the 

customer to elect to have its long-term 

firm transmission service interrupted 

under certain defined circumstances. 

This does not harm other firm 

customers. Indeed, it has precisely the 

opposite effect: it permits an 

interruption to maintain firm service to 

other customers. Moreover, we find, as 

indicated above, that conditional firm 

service is necessary to remedy undue 

discrimination. 

929. The addition of conditional firm 

service therefore does not significantly 

alter the existing balance between the 

point-to-point and network service. 

Customers of network service retain 

flexibility that is not enjoyed by pointto-point customers. Moreover, 

conditional firm does not reduce the 

availability of secondary network 

service or the ability of network 

customers to temporarily undesignate 

network resources any more than shortterm firm point-to-point service already 

reduces the availability of these network 

customer options. We therefore reject 

TDU Systems’ arguments and find that 

the addition of conditional firm service 

is necessary to remedy undue 

discrimination and will otherwise 

increase utilization of the grid without 

impairing system reliability. 

(2) Reliability 

(A) Ability to Predict Redispatch 

Opportunities and System Conditions in 

the Long Run 

Comments 

930. Some commenters state that 

redispatch, used as a planning tool 

rather than as a short-term operational 

tool, is overly complex, prone to causing 

disputes, reduces reliability and thus 

should not be included in the pro forma 

OATT.589 Southern asserts that 

planning redispatch should not be 

required where it reduces reliability by 

reducing a utility’s reserve margin, 

shifting the operational, reliability and 

economic risks from the new customer 

to native load, or causing a single 

contingency to overload the system. 

Additionally, Xcel states that pledging a 

network resource to support planning 

redispatch carries a risk of penalties for 

inadequate resources in some areas. 

MISO states that contingency conditions 

must be considered and respected when 

evaluating planning redispatch options 

so that there is no reliance on 

curtailment of service. MidAmerican 

and Progress Energy conclude that the 

customer must accept the risk of 

selecting planning redispatch service 

over transmission construction. 

931. Several commenters request 

modification of the existing planning 

redispatch provisions of the pro forma 

OATT.590 They state that the 

Commission should clarify that the 

current section 13.5 does not require 

planning redispatch when it would 

adversely affect system reliability or 

service to native load, network 

customers and other firm point-to-point 

customers or impair other contractual 

obligations. Indianapolis Power states 

that the Commission should modify 

section 13.5 to require all reasonable 

redispatch options be examined by the 

transmission provider. 

932. In its reply comments, Southern 

explains that transmission providers fail 

to provide the currently required 

planning redispatch service to point-topoint customers because the service is 

impractical and would harm reliability. 

Southern contends that a redispatch 

scenario identified in a transmission 

plan may not be available in real time 

due to outages or loop flow. Southern is 

also concerned about the complications 

in planning and modeling that would 

occur if the transmission provider is 

required to redispatch multiple 

resources in order to accommodate 

multiple planning redispatch customers. 

933. Similar to their arguments in 

favor of conditional firm, EPSA and 

AWEA state that planning redispatch is 

necessary because a transmission 

provider will reject a long-term firm 

service request unless it can satisfy 

every element of the request, even if 

reliability violations occur in only a few 

hours of the year. In its reply comments, 

EEI responds that there is no evidence 

to support the assertion that a 

transmission provider will reject a longterm firm service request unless it can 

meet every element of that request. EEI 

states that in such a situation the 

transmission provider must offer partial 

service, offer to perform a system impact 

study, and exercise due diligence in 

constructing needed upgrades to 

accommodate the request. EEI adds that 

the potential customer can also request 

short-term service. Finally, EEI states 

that there is no evidence that 

transmission providers are refusing to 

redispatch in response to customer 

request when redispatching resources 

would have no impact on reliability. In 


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591E.g., Duke, Entergy, Imperial, International 

Transmission, Salt River, Seattle, Southern, 

Tacoma, Northwest IOUs, Sacramento, Progress 

Energy, E.ON, Xcel, TVA, and EEI Reply. 

592E.g., Sacramento and TVA. 

593E.g., Progress Energy, E.ON, WAPA, Entergy, 

and MidAmerican. 

594E.g., Bonneville, Seattle, Public Power 

Council, and WAPA. 

595E.g., Ameren, Southern, and EEI. 

596A transmission provider may not be able to 

provide conditional firm service without impairing 

the reliability of its system if it is required, for 

example, to manage many conditional firm pointto-point reservations across the same path. The 

ability of system operators to track, tag and manage 

curtailment of multiple conditional firm 

reservations is necessarily limited by time, human 

resources and other reliability-related duties of the 

operators. 

its reply comments, MISO states that 

denial of service complained of by 

EPSA and AWEA is a consequence of 

the customer’s economic decision not to 

build upgrades. 

934. Many transmission providers 

assert that the costs and inequities of 

achieving the proposed planning 

redispatch outweigh any new benefits 

for point-to-point customers.591 They 

state that the Commission’s proposal is 

based on an erroneous assumption that 

redispatch is nearly always feasible; 

instead when redispatch is most 

desirable, generators operating at peak 

would not be available for redispatch.592

Southern also explains that problems of 

insufficient transmission capacity 

cannot be avoided by redispatching 

generation because there is no guarantee 

that a redispatch solution will be 

available during real-time operations. 

Imperial argues that the personnel and 

modeling costs to transmission 

providers of calculating planning 

redispatch costs prior to a facilities 

study are too excessive. Xcel concludes 

from a NERC experiment on market 

redispatch that redispatch involving 

non-market-based or bilateral 

coordination with third parties to 

protect a delivery path is cumbersome, 

inefficient, and does not promote 

reliability. 

935. Xcel states that its estimate of 

hours of planning redispatch is unlikely 

to be accurate given that it uses a static 

power flow that is created for a specific 

peak hour and a specific off-peak hour 

in a given year. Commenters state that 

planning redispatch service should not 

be a guaranteed service because 

generation or transmission availability, 

system loads, loop flows from adjoining 

systems, weather, and fuel availability 

all entail a component of risk that 

should not be pushed back on the 

transmission provider or its native 

load.593

936. Operators of systems that rely 

primarily on hydroelectric resources 

argue that planning redispatch should 

not be considered a viable option for 

their systems and they should be 

exempt from OATT planning redispatch 

obligations because hydroelectric 

operators are unable to make long-term 

commitments that a resource will be 

available to relieve transmission 

constraints.594 Bonneville states that the 

variability in water flows and the 

interdependence of the generating units 

contribute to the inability to predict 

future redispatch ability. Bonneville, 

WAPA and Bureau of Reclamation state 

that planning redispatch can conflict 

with federal obligations to operate 

federal dams and reservoirs in a manner 

that does not impact project purposes 

and provide preference in the sale of 

hydropower to its preference customers. 

Tacoma states that planning redispatch 

must be linked to market price indexes 

to work in a hydro-based system. Seattle 

states that in hydro-dominant systems 

fuel availability and fuel price risk 

undermine the feasibility of providing 

long-run redispatch cost estimates that 

reasonably reflect future costs. Seattle 

adds on reply that planning redispatch 

fails to address costs pertaining to fish 

species preservation, recreation and 

flood control impacts, increased risk of 

spill, or replacement power that are 

associated with hydroelectricity. 

937. Morgan Stanley argues on reply 

that the Commission should not exempt 

hydroelectric system operators from 

providing planning redispatch; instead, 

factors unique to hydroelectric systems 

should be taken into account in 

determining how much planning 

redispatch a transmission provider can 

provide. In supplemental comments, 

PPM agrees with Morgan Stanley and 

adds that hydro-based systems, such as 

Bonneville’s, are flexible enough for a 

transmission provider to use planning 

redispatch to create additional firm 

capacity. 

938. In their reply comments, Utah 

Municipals and EPSA state that 

planning redispatch would not impair 

reliability because the OATT provisions 

do not require transmission providers to 

permit intentional overloading of lines. 

Since transmission providers are 

already required to provide planning 

redispatch now, Utah Municipals 

contend that any change in the sequence 

for studying the option cannot have an 

impact on reliability. EPSA argues that 

claims of adverse reliability impacts 

should be dismissed because 

transmission providers do not make 

these same claims when they redispatch 

to enable transmission service to meet 

their own load obligations. Utah 

Municipals state that reliability would 

be most enhanced by completely 

restricting access to the grid, a policy 

that Utah Municipals do not 

recommend because it would be 

extraordinarily costly and promote 

discrimination. In its reply comments, 

Entegra states that customers seeking 

planning redispatch are not seeking to 

shift a disproportionate share of the 

risks or costs to native load or other 

users of the system. 

939. In its reply comments, EPSA 

further argues that the Commission 

should place the burden of showing 

unreliability in a particular instance on 

the transmission provider. EPSA also 

argues that transmission providers 

should not be allowed to delay service 

through feasibility studies. EPSA 

contends that planning redispatch will 

not delay needed system upgrades and, 

instead, will ensure optimized use of 

the existing system that will provide 

additional information about the 

system’s capabilities to regional 

planning initiatives. In its reply 

comments, Morgan Stanley states that 

the Commission should establish clear 

standards as to the degree of expected 

reliability that appends to a firm 

transmission sale and allow 

transmission providers to sell as much 

of the system as can be sold on a firm 

basis, consistent with maintaining the 

reasonable standard. 

940. EEI and some transmission 

providers add that the conditional firm 

product could result in an 

oversubscription of a transmission 

system in violation of NERC reliability 

standards that require the transmission 

system to be planned to meet all firm 

needs.595 ELCON states that conditional 

firm service may not truly support longterm contracts for firm power but may 

lead to a greater volume of short-term 

trading. 

Commission Determination 

941. Many commenters are concerned 

that the options described in the NOPR 

will impair system reliability. We have 

taken these comments into account and 

have tailored the modifications to longterm point-to-point service so as to not 

impair system reliability. There are two 

important limitations that provide such 

protections. First, we make clear that 

transmission providers are not required 

to offer planning redispatch or 

conditional firm service if doing so 

would impair system reliability.596

Second, as explained above and 

discussed in further detail below, we are 

limiting the time period under which 

either option is offered. We do so 

because forecasts of potential redispatch 

or interruption options become more 


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597See, e.g., Arizona Public Service Co. v. Idaho 

Power Co., 95 FERC ¶ 61,081 at 61,241 (2001) 

(resources projected to be unavailable during 

system peak month to provide planning redispatch). 

598E.g., Entergy. 

599See also Order No. 888 at 31,739. 

speculative over time and to require a 

transmission provider to commit for a 

substantial period of time, subject to the 

uncertainty inherent in such long-term 

projecting, has the potential to degrade 

reliability. With these two limiting 

conditions, we find that neither the 

planning redispatch nor conditional 

firm option will degrade reliability and, 

as discussed above, that both are 

necessary to remedy undue 

discrimination. 

942. We agree with a majority of 

commenters that over the long term, 

new resources should be supported by 

sufficient transmission capacity to 

deliver their output reliably. Imposing a 

planning redispatch or conditional firm 

obligation over the long-run would not 

be consistent with the need to increase 

the reliability of the grid or otherwise 

necessary to remedy undue 

discrimination. Rather, it would tend to 

degrade reliability over time, contrary to 

the public interest and the underlying 

goals of EPAct 2005. Projections of 

planning redispatch options and 

conditional firm conditions are more 

accurate in the near term and, hence, 

should facilitate the efficient use of 

existing resources without impairing 

reliability. 

943. We therefore impose limits on 

the transmission provider’s current 

planning redispatch obligations. We do 

so by removing the obligation to provide 

planning redispatch for an indefinite 

period as long as the redispatch is less 

expensive than the relevant 

transmission upgrades. Section 13.5 of 

the pro forma OATT could, in 

conjunction with rollover rights, allow 

for an extremely long-term obligation to 

provide planning redispatch in lieu of 

upgrading the transmission system. We 

find that this existing obligation may 

unreasonably harm reliability and 

provides incorrect incentives to delay 

necessary grid expansion. We 

emphasize that the obligation to provide 

planning redispatch applies only when 

the service can be provided reliably. 

944. We also limit the time period 

over which a transmission provider 

must predict the system conditions or 

conditional hours that would apply to 

customers using the conditional firm 

option. We do so in recognition of the 

difficulty in attempting to forecast 

curtailment options over the long-term 

and the fact that there is no evidence 

that transmission providers perform 

similar forecasts for their native load 

customers. We do not, however, 

eliminate entirely the risk of predicting 

future system conditions or shift it in 

whole to the requesting transmission 

customer as requested by certain 

commenters. We believe that the 

transmission provider should retain 

responsibility for incorporating 

reasonable assumptions into its 

transmission models so that it can 

manage this risk, just as it currently 

manages the prediction risk in its ATC 

models. 

945. We will now turn to certain 

clarifications and other issues raised by 

the commenters. We acknowledge that 

planning redispatch to support annual 

service may require redispatch of 

generation during the peak month or 

months. Since transmission providers 

plan their generation to meet their peak 

native load plus reserves, the 

transmission provider’s resources may, 

in some cases, be fully employed to 

meet the needs of bundled retail native 

load and thus may not be available to 

provide redispatch during the peak 

period.597 In such an instance, the 

unavailability of such resources to 

provide redispatch service will 

constitute a legitimate basis for denying 

planning redispatch service. However, 

we will not excuse the existing 

obligation that requires transmission 

providers to study any available 

planning redispatch, including 

redispatch that might provide some but 

not all of the service requested. Given 

that some transmission providers have 

acknowledged their own use of 

planning redispatch for their network 

resources,598 the service must continue 

to be available to those seeking point-topoint service to ensure comparability. 

946. We reiterate that the 

transmission provider remains obligated 

to provide planning redispatch from its 

resources as long as the planning 

redispatch does not (1) degrade or 

impair the reliability of service to native 

load customers, network customers and 

other transmission customers taking 

firm point-to-point service or (2) 

interfere with the transmission 

provider’s ability to meet prior firm 

contractual commitments to others.599

We continue to believe these are the 

appropriate exceptions and will not 

adopt a broad and undefined 

reasonableness standard as suggested by 

Indianapolis Power. We agree with 

Southern that the transmission provider 

may consider the impact of the planning 

redispatch service in reducing its 

reserve margin below that necessary to 

maintain reliability or causing a single 

contingency to overload the system in 

determining whether the service can be 

reliably provided. 

947. Further we will not excuse 

transmission providers from the 

obligation to manage multiple planning 

redispatch or conditional curtailment 

obligations simply because some 

commenters express concerns about 

planning and modeling impacts. While 

we do not take these concerns lightly, 

we believe they can be managed by 

transmission providers. The planning 

redispatch obligation has existed for ten 

years, and with it the potential for 

multiple planning redispatch requests. 

We have no evidence that transmission 

providers have been unable to manage 

the process. Moreover, by scaling back 

the time period for which transmission 

providers must plan for provision of 

redispatch, we have greatly reduced any 

planning and modeling impacts. We 

believe that whatever additional work 

the options cause with regard to 

planning and modeling, it is small and 

more than offset by the considerable 

value of the options which allow for 

more efficient use of the transmission 

system, expansion of long-term uses of 

the grid and remedying of undue 

discrimination. 

948. Finally, we recognize the 

difficulty of predicting, over prolonged 

periods, whether hydroelectric 

resources will be available to provide 

redispatch. We agree with Morgan 

Stanley that factors unique to 

hydroelectric systems should be taken 

into account in determining how much 

planning redispatch a transmission 

provider can provide. For example, 

transmission providers operating hydrobased systems must predict both system 

load growth and water availability in 

order to determine whether resources 

will be available in the next few years 

to provide redispatch. We acknowledge 

that certain circumstances may in fact 

limit long-term redispatch on these 

systems due to increased prediction 

risks. We reiterate, however, that all 

transmission providers, including those 

operating hydro-based systems, are 

required to make a determination, 

regarding whether planning redispatch 

service can be provided consistent with 

system reliability based on the specific 

facts of a particular request for service. 

The fact that hydro-based systems may 

not be able to provide planning 

redispatch service under many 

circumstances should not necessarily 

limit the availability of conditional firm 

service on these systems. We expect that 

transmission providers with hydrobased systems will focus on provision of 

the conditional firm option in a manner 

consistent with their system conditions. 


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600E.g., EEI, Duke, Imperial, LPPC, PNM–TNMP, 

Public Power Council, NRECA, NPPD, Southern, 

and Progress Energy. 

601E.g., EEI, TAPS, LDWP, MidAmerican, 

Southern, Community Power Alliance, and MISO 

Reply. 

602E.g., Duke, LPPC, NRECA, NPPD, Progress 

Energy, Southern, APPA, and South Carolina E&G. 

603Although partial interim service is not 

addressed in this rulemaking, we note that the 

OATT continues to require this service, on an as 

available basis, if a multi-year service request is 

denied. 

949. We also repeat that planning 

redispatch service does not need to be 

provided if doing so would impair the 

firmness of service to existing 

transmission customers. For example, 

pre-existing federal obligations, such as 

those described by Bonneville, WAPA 

and Bureau of Reclamation, would 

qualify as the type of firm commitments 

to others that would excuse 

transmission providers from the 

planning redispatch obligation to the 

extent that redispatch impaired service 

to these customers. 

(B) Impact on Network Customers and 

Native Load 

950. Several commenters argue that 

the use of planning redispatch may 

remove the ability to use reliability 

redispatch in real-time operations to 

respond to system contingencies, 

resulting in more curtailment of 

network and native load.600 In addition 

to reducing availability of redispatch as 

an operational tool, NRECA contends 

that planning redispatch will reduce 

ATC for network service and the 

incentive to build new transmission. 

Several commenters state that planning 

redispatch may unfairly shift costs to 

network and native load customers.601

Progress Energy argues that such a 

mandate places the power grid in 

serious jeopardy because the system has 

not been designed to handle the 

redispatch planning model. Progress 

Energy and Nevada Companies state 

that the planning redispatch option 

could conflict with transmission 

providers’ state resource planning 

obligations to reliably serve load at least 

cost. Exelon replies, however, that 

planning redispatch could increase 

flexibility for network customers by 

increasing the availability of point-topoint service across adjacent 

transmission systems to bring 

generation to network loads. 

951. Some commenters argue that the 

conditional firm option would adversely 

impact system reliability by subjecting 

firm customers to additional 

curtailments once conditional 

curtailment hours are exceeded.602

NRECA and Utah Municipals state that 

the conditional firm service will reduce 

the flexibility of network customers by 

preventing network customers from 

using secondary network service, a right 

that NRECA argues is protected by FPA 

section 217. 

Commission Determination 

952. We reiterate that transmission 

providers are not required to offer 

planning redispatch and conditional 

firm point-to-point service if doing so 

would impair the reliable service to firm 

customers, including native load and 

network customers. The concerns of the 

commenters regarding the impacts on 

native load, network and other existing 

firm uses are therefore misplaced. 

953. Transmission providers are 

already obligated to provide planning 

redispatch service pursuant to Order 

No. 888 and thus arguments that the 

planning redispatch option will harm 

existing customers is equally misplaced. 

Indeed, under the limitation on the 

duration of planning redispatch service 

imposed in this Final Rule, transmission 

providers will be able to better manage 

the risks of curtailment for current users 

of the transmission grid. This is because 

the obligation to redispatch will no 

longer be an open-ended obligation. 

Customers will need to commit to 

upgrade the system or to have their 

service reassessed periodically. Both of 

these allow the transmission provider to 

better plan to serve needs reliably 

because it reduces the unknowns. With 

regard to NRECA’s argument that 

planning redispatch will cause less 

flexibility in real-time and more 

potential for curtailments of network 

customers and bundled retail native 

load, all sales of point-to-point service 

could to some extent cause more 

curtailments of network customers and 

bundled retail native load. Our decision 

today limits the existing planning 

redispatch obligation for point-to-point 

service, rather than expanding it. 

954. Similarly, the conditional firm 

option does not reduce the availability 

of secondary network service or the 

ability of network customers to 

temporarily undesignate network 

resources any more than short-term firm 

point-to-point service already reduces 

the availability of these network 

customer options. We see no reason to 

reject the conditional firm option so that 

transmission providers avoid offering 

higher-quality service such as 

conditional firm point-to-point service 

in order to retain the ability to offer 

lower-quality service such as secondary 

network service. 

955. Finally, we believe that network 

customers can benefit from the use of 

the planning redispatch and conditional 

firm options available in a point-topoint transmission service request. As 

described below, long-term point-topoint service that employs the planning 

redispatch or conditional firm option 

would qualify as a network resource on 

any adjoining system importing that 

resource. 

(3) Implementation of Planning 

Redispatch and Conditional Firm 

Options 

956. Commenters raise various 

concerns regarding specific 

implementation issues associated with 

the planning redispatch and conditional 

firm options. We address those concerns 

below, but first provide an overview of 

the planning redispatch and conditional 

firm service required in this Final Rule 

in order to outline the new rights and 

obligations of transmission providers 

and customers. Following this overview, 

we address specific comments relating 

to the service. 

957. Pursuant to the modified 

obligations adopted in this Final Rule, 

where a request for long-term point-topoint firm transmission service is made 

and cannot be satisfied out of existing 

capacity, the transmission provider 

shall, at the request of the customer and 

in the system impact study, identify (1) 

the transmission upgrades necessary to 

provide the service, and (2) the options 

for providing service during the period 

prior to completion of those 

transmission upgrades. Additionally, if 

upgrades cannot be completed prior to 

expiration of the requested service term, 

the transmission provider shall, at the 

request of the customer and in the 

system impact study, identify options 

for providing the service during the 

requested term. The options studied by 

the transmission provider must include 

planning redispatch and conditional 

firm options.603 The transmission 

provider, at its discretion, may study 

and offer a mix of planning redispatch 

and conditional firm options for a single 

service request. We provide further 

detail on each required option below. 

958. If the transmission provider 

determines that planning redispatch is 

available, it shall provide the customer 

with non-binding estimates of the 

incremental costs of redispatch and 

identify the relevant constrained 

flowgates for which redispatch will be 

provided. For the conditional firm 

option, the transmission provider shall 

identify the conditions and hours 

pursuant to which the service may be 

curtailed, using a secondary network 

curtailment priority, to maintain 

reliability. Specifically, the transmission 

provider shall identify (1) the specific 


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604For example, if a transmission provider opts 

to forego the reassessment at the end of year two, 

the transmission provider may not reassess the 

conditions of the service again until the end of year 

four of service for imposition of new conditions 

starting in year five. 

605E.g., Progress Energy Supplemental, PNMTNMP Supplemental, LPPC Supplemental, APPA 

Supplemental, TAPS Supplemental, TDU Systems 

Supplemental, NRECA Supplemental, EEI 

Supplemental, Entergy Supplemental, Ameren 

Supplemental, Powerex Supplemental, and MISO 

Supplemental. 

606E.g., Bonneville Supplemental, PPL 

Supplemental, EPSA and AWEA Supplemental, EEI 

Supplemental, Barrick Supplemental, and 

Constellation Supplemental. 

607E.g., Xcel Supplemental, Duke Supplemental, 

and EEI Supplemental. 

system condition(s) when conditional 

curtailment may apply and (2) the 

annual number of hours when 

conditional curtailment may apply. 

Customers agreeing to take conditional 

firm service must choose one of these 

options, conditions or hours. 

959. Where the customer requests 

firm service for more than two years, but 

is unwilling to commit to a facilities 

study or the payment of network 

upgrade costs, the transmission provider 

shall identify and provide the planning 

redispatch or conditional firm options 

subject to the following limitation. The 

transmission provider shall have a 

periodic right to reassess (1) the 

planning redispatch required to keep 

the service firm or (2) the conditions or 

hours under which the transmission 

provider may conditionally curtail the 

service. This reassessment may occur 

every two years during the term of the 

service, i.e., at the end of year two, year 

four, year six, and year eight of a tenyear service. The transmission provider 

may not implement reassessments 

during intervening periods nor may it 

reassess the conditions in order to 

amend the service agreement in an 

intervening year should it forego any 

biennial reassessment.604

960. The service agreement shall 

specify the relevant congested 

transmission facilities and whether the 

transmission provider will provide 

planning redispatch, a mix of planning 

redispatch and conditional firm, or 

conditional firm in order to provide the 

point-to-point transmission service. For 

the conditional firm option, customers 

must choose among and the service 

agreement must specify either (1) 

specific system condition(s) during 

which conditional curtailment may 

occur or (2) annual number of 

conditional curtailment hours during 

which conditional curtailment may 

occur. We deem that any service 

agreement that incorporates planning 

redispatch or conditional firm options is 

a non-conforming agreement and must 

be filed by the transmission provider 

pursuant to section 205 of the FPA. 

Additionally, transmission providers 

must file with the Commission any 

amendments to these service agreements 

that result from reassessments. If a 

transmission provider proposes to 

change the redispatch or conditional 

curtailment conditions due to a 

reassessment, the transmission provider 

must provide the reassessment study to 

the customer along with a narrative 

statement describing the study and 

reasons for changes to the curtailment 

conditions or redispatch requirements 

no later than 90 days prior to the date 

for imposition of these new conditions 

or requirements. The transmission 

provider shall assess the conditions 

based on two years of service or the 

continuation of the term of service, 

whichever is less. 

961. In situations in which the 

customer commits to paying the costs 

associated with upgrades necessary to 

provide the service on a fully firm basis, 

the conditions or hours identified by the 

transmission provider shall remain in 

effect until such time as the upgrades 

have been completed. Also, for such 

customers, the service agreement shall 

specify the upgrade costs as determined 

through the facilities study. 

(A) Eligibility for and Timing of 

Planning Redispatch and Conditional 

Firm Options 

NOPR Proposal 

962. In the NOPR, the Commission 

proposed that customers who request 

long-term firm point-to-point 

transmission service and have the 

service denied because of lack of ATC 

would be eligible to receive planning 

redispatch service or, if the Commission 

chose to adopt the conditional firm 

service option, conditional firm service. 

The Commission also proposed earlier 

evaluation of the planning redispatch 

option in the system impact study rather 

than in the facilities study. The 

Commission proposed that, if it were to 

adopt conditional firm service, the 

evaluation of conditional firm 

availability should occur prior to a 

system impact study or facilities study. 

Comments 

963. If the conditional firm option is 

required by the Commission, many 

commenters believe it should be a 

bridge product to span the gap between 

when the relevant transmission service 

request is being studied and when the 

relevant upgrades become 

operational.605 These commenters state 

that a bridge product is appropriate 

because it would not depress funding 

for new transmission infrastructure and 

would better meet the NOPR’s and 

Congress’ grid expansion objectives. In 

their view, use of a bridge product 

would avoid equity and free rider 

problems that may occur if a conditional 

firm customer is taking long-term 

service and the transmission system is 

upgraded during that service. They also 

argue that the bridge product would 

better allow for transmission providers 

to judge the likelihood of curtailment 

and avoid complicated system modeling 

and planning issues; as well as protect 

existing long-term transmission 

customers. Duke and Ameren state that 

an annual re-determination of the 

conditional period is necessary for a 

bridge product. If the upgrade has not 

been completed within a three year 

period, NRECA suggests that the 

customer be required to make a new 

long-term firm service request so the 

provider can update to reflect system 

conditions at that time. 

964. Several commenters suggest that 

transmission providers should offer 

conditional firm service as both a bridge 

product and as a stand-alone long-term 

firm service.606 Where not used as a 

bridge service, several commenters state 

that it should be limited to reservations 

that do not have rollover rights.607 Duke 

argues that the service duration for nonbridge service should be one year, but 

with renewal rights that give the 

conditional firm customer a priority 

over other non-bridge conditional firm 

service customers seeking capacity. 

APPA supports one to two-year service 

offers. 

965. In supplemental comments, EEI 

supports a voluntary conditional firm 

product with three types of service: A 

one-year product with no rollover 

rights; a bridge product for a term of 

more than one year that is provided 

until upgrades necessary to 

accommodate a firm service request are 

completed; and a non-bridge product of 

more than one year, with no rollover 

rights or transmission provider 

obligation to construct upgrades and 

subject to the transmission provider’s 

periodic review of its system capability 

to provide such service. EEI contends 

that the Commission should encourage 

transmission providers to offer 

conditional firm service for more than 

one year without rollover rights to a 

customer that is not willing to take 

service of sufficient length to allow 

recovery of upgrades costs, if such 

service can be provided without 

affecting the reliability and quality of 

service to firm transmission customers. 

966. In support of limitations on the 

term of conditional firm service, many 


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608E.g., Nevada Companies Supplemental, TDU 

Systems Supplemental, LPPC Supplemental, 

Ameren Supplemental, Community Power Alliance 

Supplemental, MISO Supplemental, PNM-TNMP 

Supplemental, NRECA Supplemental, and Xcel 

Supplemental. 

609EPSA and AWEA endorse Constellation’s 

approach in defining and delineating the two forms 

of conditional firm service. 

610E.g., Nevada Companies Supplemental, Duke 

Supplemental, Bonneville Supplemental, Powerex 

Supplemental, BP Energy Supplemental, MISO 

Supplemental, PNM–TNMP Supplemental, Entergy 

Supplemental, Community Power Alliance 

Supplemental, and Southern Supplemental. 

611 Proposals regarding the ‘‘higher of’’ pricing 

policy are discussed below. 

612E.g., Xcel Supplemental, Constellation 

Supplemental, and NRECA Supplemental. 

613 In the November 15 Notice, the Commission 

described an example of lumpy capacity as 

upgrades to provide a requested 100 MW of pointto-point service that results in 1,000 MW of 

additional transmission capacity. 

614E.g., EEI Supplemental, Xcel Supplemental, 

APPA Supplemental, Bonneville Supplemental, 

LPPC Supplemental, NRECA Supplemental, 

Progress Energy Supplemental, Duke Supplemental, 

Ameren Supplemental, Entergy Supplemental, 

Community Power Alliance Supplemental, MISO 

Supplemental, Williams Supplemental, and PNMTNMP Supplemental. 

615E.g., LPPC Supplemental, Bonneville 

Supplemental, and EEI Supplemental. 

commenters state that analyzing and 

modeling system conditions will always 

be more accurate in the near term than 

in the long term.608 EEI and Community 

Power Alliance believe that limitations 

on system modeling prevent many 

transmission providers from accurately 

evaluating their ability to provide 

conditional firm service over long 

periods. According to EEI, system 

conditions change on both the 

transmission provider’s and neighboring 

systems substantially affecting the 

ability of the transmission provider to 

provide conditional firm service and the 

periods such service is subject to 

curtailment. While system loads can be 

predicted with a reasonable degree of 

accuracy for more than one year, other 

components of the prediction model, 

such as transmission and generator 

outages, typically are not determined 

more than a year in advance. For 

example, EEI states that members in the 

SERC region coordinate transmission 

and generation outages in a 13-month 

planning horizon. Duke states that the 

ability to model the system varies 

significantly by region. Entergy and 

MidAmerican believe that system 

modeling limitations would present 

serious reliability problems if 

transmission providers were required to 

offer a multi-year conditional firm 

transmission product because even the 

most advanced modeling software 

cannot predict long-term conditions that 

may affect service. Entergy and 

MidAmerican propose that the 

Commission allow transmission 

providers to update the curtailment 

criteria for a reservation, to reflect, 

among other things, changing load 

assumptions and forecasts over time. 

MidAmerican argues that without 

annual reevaluation there would be cost 

shifts to other firm customers. In its 

reply comments, MidAmerican explains 

that this reevaluation can only occur 

when the actual data becomes available 

for projecting potential curtailment 

hours. 

967. If a transmission provider offers 

conditional firm service based on 

specified system conditions, Bonneville 

states in supplemental comments that 

limitations on modeling do not present 

a problem. If, however, the service is 

based on a maximum number of 

conditional curtailment hours per year, 

Bonneville believes that modeling 

presents problems in offering longerterm service. Bonneville states that 

forecasting the number of hours of 

conditional firm service requires great 

analysis. To remedy this, Bonneville 

suggests allowing the transmission 

provider to make conditional firm offers 

under which the transmission provider 

could periodically adjust the number of 

conditional curtailment hours. 

968. In supplemental comments, 

Constellation proposes that the 

Commission require transmission 

providers to offer two types of 

conditional firm service: service for less 

than the service term eligible for 

rollover rights (e.g., five years) if 

customers do not agree to pay for 

transmission upgrades; and service for 

five years or longer with a rebuttable 

presumption that the customer is 

obligated to pay for upgrades that are 

both economic and necessary to relieve 

the constraint that prevents its service 

from being fully firm.609 EPSA and 

AWEA maintain that it is critical that 

the conditions be defined, and remain 

unchanged, for the term of the service 

agreement in order to obtain financing 

of new projects. EPSA and AWEA also 

propose that, if the contingency is 

removed during the life of the 

customer’s conditional firm service, the 

service should convert to traditional 

firm service. Williams, EPSA and 

AWEA argue that up-front commitment 

to continue the conditions for the 

entirety of a long-term service 

agreement would take no greater risk 

than transmission providers take today 

in committing to other long-term firm 

transmission service. EPSA and AWEA 

state that limited term conditional firm 

service should pose no problems based 

on system modeling. 

969. Several commenters believe that 

there is no need for any type of special 

rules for conditional firm customers 

taking bridge service and required to 

pay extremely expensive upgrades.610 If 

the Commission abandons the ‘‘higher 

of’’ pricing principle for upgrades, these 

commenters suggest that any new 

pricing policies should be consistent 

with cost-causation principles and not 

result in any improper socialization.611

Other commenters argue for special 

rules when upgrades are extremely 

expensive.612 Xcel states that customers 

should have the option to take shortterm conditional firm service that would 

remain subject to limitation and 

curtailment if upgrades are too 

expensive. Constellation proposes that 

customers taking the longer-term service 

should have the opportunity to show 

that upgrades would not be just and 

reasonable given the relevant 

circumstances, e.g., the cost of upgrades 

for a single service request is $300 

million. If the Commission determines 

that the bridge requirement in a 

particular circumstance is unjust and 

unreasonable, Constellation proposes 

that the transmission provider would 

provide the service for the requested 

term, but there would be no obligation 

for the transmission customer to pay for 

such upgrades, and the service would 

not be eligible for rollover. NRECA 

contends that instances in which special 

rules apply should be extremely rare 

and are best addressed by the 

transmission provider and customers on 

an ad hoc basis. 

970. Commenters recognize that 

upgrades required under a bridge 

conditional firm option could create 

lumpiness problems,613 but most 

commenters suggest that this problem is 

not unique to the conditional firm 

option, nor can it be resolved through 

use of the option.614 These commenters 

support continuation of the 

Commission’s existing policies with 

regard to lumpiness issues, and some 

suggest the need to address the issue as 

it pertains to all upgrades in a future 

proceeding.615 In contrast, a few 

commenters suggest that the 

Commission should address the 

lumpiness issue with regard to 

conditional firm service. PPL, EPSA and 

AWEA state that the transmission 

provider should be required to pay the 

costs of any incremental lumpiness 

associated with upgrades and the 

service request. BP Energy contends that 

any lumpy capacity needs to be resolved 

on a bilateral contractual basis. Powerex 

suggests using an ‘‘open season’’ process 

to finance expensive and lumpy 

upgrades. California Commission 

supports prorating large lumpy 


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616E.g., Xcel, PPM, and BP Energy. 

617E.g., EEI, Southern, TVA, SPP, E.ON, and 

MISO. 

618E.g., APPA, PNM–TNMP, and Southern. 

upgrades over a large base of new 

customers, to the extent that it is nondiscriminatory and fiscally sound. 

971. In supplemental comments, 

Nevada Companies urge that the time 

period of a conditional firm bridge 

product should be left up to the 

discretion of each transmission 

provider. They suggest that most, if not 

all, transmission providers should be 

able to offer a conditional firm service 

for a one-year period and most should 

be able to offer it for longer periods. 

Nevada Companies state that they 

should be able to provide conditional 

firm service in their control areas for 

longer periods, possibly for up to five 

years in some circumstances and in 

certain locations. 

972. BP Energy and Williams disagree 

that conditional firm service should be 

a bridge product. They state that such a 

limitation would provide additional 

opportunities for undue discrimination 

and limit competitive alternatives used 

to serve customer load. According to 

California Commission, conditional firm 

service needs to be available for longterm requests unless there exists a valid, 

proven reason why conditions make it 

physically or economically impossible 

to guarantee such service. California 

Commission states that some limitations 

on modeling should be accepted as 

justification for not providing 

conditional firm or related services only 

if such provisions for load growth are 

nondiscriminatory, justified and 

contractually sound. 

973. Commenters take both sides on 

whether planning redispatch should be 

evaluated before the customer is 

obligated to incur the costs and delays 

of a facilities study. EPSA argues that 

evaluation prior to a facility study meets 

nondiscrimination requirements given 

the methods used by transmission 

owners to evaluate planning redispatch 

for their own needs. In its reply 

comments, Exelon supports the minor 

changes to planning redispatch 

proposed by the Commission, including 

the earlier study of planning redispatch 

options in the system impact study, and 

states that these changes will expand 

choices for customers. EEI states that 

requiring an offer of planning redispatch 

prior to completion of a facilities study 

would be unduly preferential to pointto-point customers because transmission 

providers consider the costs of network 

upgrades and the impacts on system 

reliability before choosing planning 

redispatch for their native load. 

Southern points to the internal 

inconsistencies of the NOPR that on one 

hand seek to expedite the study process 

and on the other hand would require a 

planning redispatch study provision 

that would slow the study process. 

974. EEI states that the vast majority 

of facilities studies show that the 

embedded cost of transmission service 

is higher than the incremental 

amortized cost of upgrades. Thus, EEI 

argues that the Commission’s proposal 

to reform planning redispatch could 

lead to uneconomic decisions by the 

customer as well as provide 

disincentives to upgrade and expand 

transmission infrastructure.616 In their 

reply comments, Utah Municipals 

respond that most of the time the 

embedded cost of transmission is higher 

than the costs of upgrades, adding that 

customers find requests for a 

transmission upgrades to be a time 

consuming and costly impediment to 

transmission access. Further, Utah 

Municipals add that limited and 

occasional redispatch or curtailment, 

would be more economically efficient 

than the construction of transmission 

facilities most of the time. 

975. Several commenters state that it 

would be extremely burdensome to 

develop, at the system impact study 

stage, a reliable estimate of the number 

of hours of redispatch and the cost of 

the planning redispatch.617 These 

commenters state that this would 

require substantial investment in 

probabilistic studies of equipment 

availability and extensive training of 

personnel and expansion of data 

collection, yet still would not provide 

reliable estimates of the number of 

hours or costs of the service. MISO 

states that at a minimum, this would 

require two years to implement. 

976. EEI asserts that conditional firm 

service should be determined based on 

system impact studies and facilities 

studies so that the customer can 

evaluate the costs of upgrades versus the 

lack of reliability of the conditional firm 

service. EEI and others also propose that 

conditional firm service only be 

available when upgrades cannot be 

completed during the term of service or 

during the period prior to completion of 

transmission upgrades.618 In its reply 

comments, Bonneville disagrees that 

conditional firm service should be an 

interim service available only when the 

customer has agreed to pay for 

upgrades, stating that such a 

requirement would undercut the value 

of conditional firm service. Bonneville 

adds that, for example, the costs to build 

upgrades in order to resolve a constraint 

in a two-month period could raise the 

costs of the conditional firm service to 

a prohibitive level for little additional 

benefit to the customer. 

Commission Determination 

977. As we explain above, the 

Commission finds that both planning 

redispatch and conditional firm pointto-point service must be offered under 

certain circumstances for the provision 

of reliable and non-discriminatory 

point-to-point transmission service. We 

set forth below the parameters of this 

service, keeping in mind the concerns 

expressed by commenters. 

978. First, the planning redispatch 

and conditional firm options need only 

be made available to customers who 

request firm point-to-point service of 

more than a year in duration. When the 

requested firm point-to-point service is 

not available and the customer agrees to 

a system impact study, the transmission 

provider must evaluate the planning 

redispatch and conditional firm option 

at the customer’s request. If the 

customer requests study of the planning 

redispatch or conditional firm options, 

the system impact study must identify 

the following: (1) The system 

constraints, identified by transmission 

facility or flowgate, causing the need for 

the system impact study; (2) additional 

direct assignment facilities or network 

upgrades required to provide the 

requested service; (3) redispatch 

options, including an estimate of the 

incremental costs of redispatch and the 

relevant congested transmission 

facilities for which redispatch will be 

provided; and (4) conditional firm 

options, including the number of 

conditional curtailment hours and the 

specific system conditions during which 

conditional curtailment may occur. 

Transmission providers may recover the 

costs of studying these options through 

the system impact study agreement. 

979. Second, we adopt limitations on 

the nature of the planning redispatch 

and conditional firm options to reflect 

the two different types of customers that 

may request the service: customers who 

support the construction of upgrades 

and those who do not. 

980. For customers supporting the 

construction of upgrades, the planning 

redispatch or conditional firm options 

will serve as a bridge until upgrades are 

constructed to remedy the congested 

transmission facilities. For these 

customers, the transmission provider 

must offer planning redispatch or 

conditional firm service until the time 

when the upgrades are constructed. The 

conditions or redispatch applicable to 

this period must be specified in the 

service agreement and are not subject to 

change. We impose this requirement 


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619See pro forma OATT section 19.3. 

because customers who commit to 

support transmission upgrades are 

typically those financing and 

constructing new resources. These 

customers require certainty both with 

regard to upgrade costs and, before 

upgrades can be constructed, the 

redispatch requirements or curtailment 

conditions that may apply to their 

service. We disagree with Williams and 

BP Energy that requiring transmission 

providers to offer this bridge product 

will present more opportunities for 

undue discrimination. As we note 

above, available information on 

transmission providers’ current uses of 

redispatch and curtailment plans for 

their retail native load indicates that the 

mechanisms are used for relatively short 

periods of time until upgrades are 

completed to resolve the transmission 

insufficiencies. Comparable services for 

long-term point-to-point customers 

should therefore be similarly limited to 

shorter time periods or otherwise linked 

to transmission upgrades. 

981. For customers choosing not to 

support the construction of new 

facilities, the planning redispatch or 

conditional firm options also must be 

made available as a reassessment 

product, i.e., subject to certain 

limitations. Although many 

transmission providers argue that 

planning redispatch and conditional 

firm service should be offered only to 

customers who seek to upgrade the grid, 

we disagree. We find that there are 

legitimate circumstances under which 

customers may not choose to support 

system upgrades—either because the 

costs of construction are too high or 

because the term of service (e.g., less 

than five years) does not merit the 

construction of additional facilities. We 

will therefore make planning redispatch 

and conditional firm service available to 

such customers, but subject to certain 

limitations to reflect the nature of the 

services. Specifically, we must select a 

limitation on the term for the conditions 

that permit interruption or redispatch, 

given that, for these customers, the term 

is not circumscribed by the period 

during which upgrades are constructed. 

We adopt two years as the appropriate 

time period to allow the transmission 

provider to reassess the conditions 

under which planning redispatch or 

conditional firm service is provided. 

The transmission provider will retain 

the right to reassess the planning 

redispatch and conditional firm option 

after the first two years of service, and 

every two years thereafter. The 

transmission provider shall reassess (1) 

the redispatch required to keep the 

service firm or (2) the conditions or 

hours under which the transmission 

provider may conditionally curtail the 

service. The customer will receive 

service for the requested term unless the 

transmission provider determines 

through its biennial reassessment that 

the firm point-to-point service can no 

longer be reliably provided. The 

customer may also choose to terminate 

the service at the time of reassessment 

if the service no longer meets it needs. 

982. We select two years as providing 

a reasonable balance between the 

concerns of potential customers and 

transmission providers. We recognize 

that a shorter period would increase the 

reliability of predictions, as sought by 

certain transmission providers, but find 

that a two-year period is consistent with 

the bridge concept, given that two years 

is often less than the typical time to 

construct new facilities. While this is a 

shorter period than some transmission 

customers would desire, customers who 

require greater certainty over the longterm can obtain that certainty by 

agreeing to support the construction of 

new facilities. In the long run, all firm 

transmission customers, including 

conditional firm customers, should 

support the expansion of the grid to 

reliably serve load. 

983. We decline to adopt any of the 

suggestions to address unique 

circumstances that may arise in which 

upgrades are prohibitively expensive. 

Specifically, we will not adopt 

Constellation’s suggestion that 

customers be able to rebut the 

presumption that required upgrades are 

just and reasonable. In this Final Rule, 

we provide customers with the option of 

obtaining planning redispatch or 

conditional firm service for a long term, 

with the ability to roll over a five-year 

or longer reservation, subject to a 

limitation that the underlying 

restrictions on the service, i.e., the 

conditions for redispatch or curtailment, 

may be reassessed by the transmission 

provider every two years. We believe 

that this option is superior to that 

proposed by Constellation because it 

will provide the customer with rollover 

rights while ensuring that transmission 

providers can reliably operate their 

transmission systems. Additionally, 

since issues of lumpy capacity are 

present in the provision of transmission 

services generally, we will not address 

such issues in this Final Rule as they do 

not present issues unique to planning 

redispatch or conditional firm options. 

984. Contrary to the assertion of 

several commenters, we believe that 

transmission providers would take 

greater risk in committing to conditions 

for the entire term of a 10-year 

conditional option than they take today 

in committing to provide unconditioned 

firm point-to-point transmission service 

for a similar period. Planning for 

reliable service for existing transmission 

customers is a difficult process, but it is 

much more difficult to plan over an 

extended long-term period for reliable 

service when the service is firm for most 

of the hours of the year and less firm for 

other hours. This is because many 

transmission providers use annual 

hourly peak load for two to 10-year 

planning purposes. They would need to 

substantially change their planning 

methods to ensure no change in service 

for a conditional firm customer that is 

not expected to be served during the 

peak hour. We therefore adopt a two 

year assessment window to provide an 

appropriate degree of flexibility for 

transmission providers’ planning needs. 

985. We acknowledge, however, that 

some commenters, such as Bonneville 

and Nevada Power, state that they may 

be able to provide conditional firm 

service over a period longer than two 

years, without the need for 

reassessment. The Commission 

encourages the provision of planning 

redispatch or conditional firm service 

for longer periods where it is practical. 

In the event a transmission provider is 

able to extend the assessment period, 

we will allow the transmission provider 

to waive or extend its right to reassess 

the availability of the option, provided 

that the waiver or extension is provided 

consistently for all similarly situated 

service. 

986. With regard to timing of the 

study of planning redispatch and 

conditional firm options, the 

Commission finds that study of both 

options is appropriate in the system 

impact study. The obligation for the 

transmission provider to study planning 

redispatch options in the system impact 

phase is already present in the existing 

OATT.619 The Commission clarifies in 

this Final Rule the specific requirements 

necessary to meet this obligation. 

Transmission providers, when 

requested by potential customers, must 

provide non-binding estimates of the 

incremental costs of planning 

redispatch and identify the relevant 

congested transmission facilities for 

which redispatch will be provided. 

Transmission providers will not be 

required to estimate the number of 

hours of redispatch that may be required 

to accommodate the requested service as 

proposed in the NOPR. The Commission 

is persuaded by commenters that such 

an estimate is of limited use to potential 

customers and is difficult, expensive 

and time consuming for transmission 


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620 In section V.D.5.a, we adopt a requirement 

that transmission providers post metrics on their 

performance in processing system impact studies 

and facilities studies. 

621E.g., MISO, PJM, California Commission, and 

ISO New England. 

622E.g., AWEA, Indianapolis Power Reply, and 

Exelon Reply. 

623Citing Attachment AC of the SPP OATT 

(Optimal Reservation Processing Method for Short 

Term Firm Transmission Services). 

providers to calculate with any 

accuracy. 

987. Finally, the Commission 

disagrees that the study of planning 

redispatch options must necessarily go 

hand in hand with the study of the costs 

and construction requirements of 

facility upgrades. Again, the obligation 

to study planning redispatch in the 

system impact study is not new. Our 

action in reinforcing this existing 

obligation cannot violate comparability 

or, in itself, cause the slowing of study 

processes. We have moved to a later 

study of conditional firm options so that 

both options can be studied in tandem. 

Furthermore, we note that the structure 

of the reassessment product requires the 

study of both options at the system 

impact study phase, since by definition 

customers opting for the reassessment 

product are not likely to enter into a 

facilities study agreement. We 

acknowledge that the few changes that 

we are making to the planning 

redispatch obligation may increase 

requests for study of the option and 

certainly the new conditional firm 

option will need more study than in the 

past. While we recognize the tension 

between the adoption of requirements to 

speed study completion and the 

increase in studies’ complexity caused 

by the conditional firm option,620 we 

will not forego a beneficial new option 

for customers because of this tension. 

We expect that transmission providers 

will be diligent in completing the 

system impact studies and in bringing to 

our attention any difficulties in meeting 

deadlines caused by the study of the 

two options. 

(B) Who Must Provide Planning 

Redispatch and Conditional Firm 

NOPR Proposal 

988. In the NOPR, the Commission 

requested comment on the applicability 

of these two options to transmission 

providers who operate as RTOs and 

ISOs. The Commission also requested 

comment on which resources should be 

required in the provision of planning 

redispatch. First, the Commission 

proposed that the planning redispatch 

requirement apply to the redispatch of 

the transmission provider’s own 

generation resources, but not to obligate 

transmission providers to purchase new 

resources to provide the service. If a 

transmission provider cannot 

accommodate a long-term firm point-topoint transmission request through 

planning redispatch, the Commission 

proposed requiring the transmission 

provider to identify additional 

generators in other control areas that 

could relieve the constraint. The 

Commission also requested comment on 

whether the planning redispatch 

obligation should be expanded to 

require the use of network customer 

resources in addition to transmission 

provider resources or expanded to 

require that transmission providers 

contract to purchase off-system 

resources to facilitate the planning 

redispatch. 

(i) Application to RTOs and ISOs 

Comments 

989. RTOs state that reforms regarding 

planning redispatch and conditional 

firm services are unnecessary in RTO 

markets with financial congestion 

management because these markets 

already provide sufficient redispatch 

inside RTOs and sufficient 

interconnection service for generators 

located at RTO boundaries to address 

the Commission’s point-to-point service 

concerns.621 Ameren and MISO add that 

the options could disrupt the 

distribution of financial transmission 

rights in RTO markets. Others disagree 

and argue that planning redispatch 

should be used by RTOs to define the 

current and future operational 

environment to ensure that systems are 

not overbuilt.622 AWEA contends that, 

since RTOs and ISOs vary considerably 

in the services they offer, RTOs and 

ISOs should be required to demonstrate 

that their services are consistent with or 

superior to planning redispatch and 

conditional firm services. In particular, 

AWEA argues that RTOs that do not 

provide financial rights should be 

required to provide both of these 

services. Exelon states on reply that the 

Commission has proposed minor 

changes to the existing planning 

redispatch requirement that should not 

be impractical or too burdensome for 

RTOs to administer. 

990. In its reply comments, California 

Commission adds that capping the 

frequency or costs of redispatch in an 

RTO market would inappropriately shift 

the costs of congestion to others. 

Although SPP has successfully used 

planning redispatch to facilitate shortterm firm transmission service and to 

address interim circumstances 

associated with long-term firm 

transmission service,623 it argues that 

the Commission’s proposed expanded 

planning redispatch service would slow 

its batch processing of transmission 

service, require significant investment 

of time to evaluate the options given the 

scope of an RTO, and create speculative 

redispatch estimates at best. SPP adds 

that RTOs should simply assist the 

customer with identification of planning 

redispatch options so that the customer 

can bilaterally contract with the 

generation owners of its choice. 

991. MISO adds that conditional firm 

is inconsistent with RTO market 

mechanisms, requires burdensome 

changes to curtailment protocols and 

reliability coordinator’s procedures, and 

would impact every tool used in real 

time for congestion management in 

RTOs. In its reply comments, MISO 

adds that adoption of conditional firm 

service would require revisions to seams 

agreement protocols. California 

Commission states on reply that the 

added administrative complexity of 

conditional firm service is unnecessary 

in the CAISO because the ISO’s 

transmission service model makes no 

distinction between firm and non-firm 

service and provides prospective new 

customers with information to 

objectively estimate curtailments. 

FirstEnergy and MISO express concern 

regarding disruption of existing RTO 

communication protocols if these 

services are required in RTOs. 

Commission Determination 

992. Notwithstanding the 

requirements of section IV.C of this 

Final Rule, the Commission finds that it 

would be inappropriate to require RTOs 

and ISOs with real-time energy markets 

to adopt the provisions for conditional 

firm point-to-point service. Customers 

transacting in RTOs and ISOs are able 

to buy through transmission congestion 

in the RTOs’ real-time energy markets 

and need no prior reservation in order 

to access transmission. Voluntary 

curtailment in order to access 

transmission is thus not an attractive 

option given the range of options 

available for customers transacting in 

RTOs and ISOs. Further, in RTOs and 

ISOs with financial transmission rights, 

conditional firm service may disrupt the 

distribution of these rights. We therefore 

believe that there is no need to reform 

existing RTO and ISO procedures to 

satisfy concerns underlying the 

adoption of the conditional firm option. 

993. The Commission directs, 

however, RTOs and ISOs that already 


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624This includes the transmission provider’s 

obligation to post monthly redispatch costs for each 

transmission facility over which planning and 

reliability redispatch are provided. 

625E.g., Ameren, PNM–TNMP, Xcel, and WAPA. 

626E.g., Southern, FirstEnergy, MidAmerican, and 

Community Power Alliance. 

627E.g., AWEA, Project for Sustainable FERC 

Energy Policy, Exelon, Powerex, Constellation, 

Williams, Sempra Global, PJM, EPSA, and Entegra 

Reply. Sempra Global contends that the 

Commission should require transmission providers 

to offer redispatch of non-affiliated resources both 

within and outside its footprint, subject to preexisting contractual commitments. 

628E.g., Xcel, PNM–TNMP, and Public Power 

Council Reply. 

provide planning redispatch pursuant to 

section 13.5 of the pro forma OATT to 

modify the relevant provisions of their 

tariffs consistent with our directives in 

this Final Rule.624 RTOs and ISOs need 

not amend their tariffs if the 

Commission has previously found that 

these tariffs were just and reasonable 

without the inclusion of pro forma 

section 13.5 planning redispatch 

provisions. We will not require 

incorporation of the more limited 

planning redispatch obligations adopted 

in this Final Rule if RTOs and ISOs have 

already been excused from the planning 

redispatch obligations of the existing 

pro forma OATT. 

(ii) Generation Resources Required for 

Planning Redispatch 

Comments 

994. Most commenters agree that 

resources in addition to the 

transmission provider’s resources can 

and should participate in the provision 

of planning redispatch. Commenters 

differ as to whether this participation 

should be mandatory or voluntary. A 

few commenters maintain that 

participation by resources outside the 

transmission provider’s control area 

could have adverse impacts on 

reliability in the control area.625

995. In arguing for mandatory 

participation, EEI and others contend 

that all generation resources owned or 

operated by all jurisdictional 

transmission customers in the control 

area or balancing authority area should 

be obligated to redispatch to 

accommodate new requests for service 

in order to avoid undue 

discrimination.626 Exelon argues that 

transmission providers should 

redispatch resources of its network 

customers, subject to appropriate 

compensation. SPP contends that 

generation affiliated with transmission 

owners that have transferred functional 

control of their transmission assets to an 

RTO should not have any greater 

planning redispatch obligation than 

unaffiliated generation. In its reply 

comments, Entergy states that the 

Commission at a minimum should 

continue to allow network customers to 

request that transmission providers 

redispatch network customer resources 

in order for the customer to designate a 

new network resource. 

996. Others argue for a least-cost 

economic dispatch to relieve real-time 

system constraints, including not only 

the transmission provider’s own 

resources and those of its network 

customers, but also all non-affiliated 

resources both within and outside its 

footprint that choose to be included.627

EPSA explains that this redispatch 

would: Require transmission providers 

to solicit offers from resources to 

provide energy and perhaps ancillary 

services; be based on a resource’s offer 

of service and take into account 

generating resource and transmission 

operating limits; include performance 

assurance terms, unit commitment 

procedures, billing, compensation and 

bidding protocols, confidentiality 

protections, and information-sharing 

protocols; and dispute resolution 

procedures to avoid disputes rising to 

the level that would require judicial or 

regulatory intervention. AWEA supports 

Deseret’s OATT provisions that require 

the transmission provider to relieve 

constraints by the least cost means, 

whether by seeking a change in 

generation output from the transmission 

provider’s merchant function or from 

any other feasible generator. Williams 

suggests that independent generators 

must be allowed to participate in the 

provision of planning redispatch service 

through submission of a formulary rate 

to the transmission provider. If the 

Commission intends to have nonaffiliated generators participate in 

planning redispatch, PPL states that the 

Commission should require 

transmission providers to negotiate 

agreements with generators on their 

systems. 

997. TranServ, MidAmerican, and 

Nevada Companies support a planning 

redispatch service similar to that 

employed by the Mid-Continent Area 

Power Pool, whereby customers arrange 

for their own redispatch through 

bilateral or centralized energy markets 

and submit plans for approval to their 

transmission provider and reliability 

coordinator. 

998. Several commenters discuss the 

need for market development in 

conjunction with the planning 

redispatch obligation. TranServ and 

Xcel state that the planning redispatch 

option may force transmission providers 

without generation assets to develop 

some form of energy market to arrive at 

the costs of redispatch. Southern and 

Progress Energy add that forced 

adoption of such a market would raise 

significant political opposition and be 

contrary to the Commission’s 

commitment in the NOPR to avoid such 

restructuring. 

999. EPSA, AWEA and PJM support 

such market development. When a 

generator in another control area is 

called upon to relieve a constraint in 

regions not administered by an RTO, 

PJM states that the Commission must 

direct the development of an alternate 

LMP pricing scheme to establish 

‘‘system marginal costs’’ that are 

consistent with transparent generator 

pricing in RTO markets. EPSA and PJM 

argue that vertically integrated utilities 

in non-RTO areas should turn over 

functional control of their dispatch 

function to a disinterested entity or 

replicate the transparency by publishing 

generation dispatch. EPSA suggests that 

the Commission require this 

transparency to ensure 

nondiscriminatory redispatch. 

1000. A few commenters state that 

any requirement for the transmission 

provider to purchase generation from 

outside the control area to facilitate 

planning redispatch is functionally 

unworkable and would adversely 

impact reliability.628 EEI supports the 

Commission’s proposal to have 

transmission providers identify offsystem resources that could provide 

planning redispatch but requests 

clarification that no additional 

investigations or studies are required to 

identify these additional options. 

MidAmerican adds that the coordinated, 

open and transparent planning 

provisions of the NOPR should provide 

customers with the ability to identify 

off-system resources. EEI and Southern 

state that any redispatch on adjacent 

systems should be arranged by 

transmission customers and the service 

should be curtailed prior to other firm 

uses of the system if the off-system 

generator fails to perform. WAPA and 

Bonneville argue against the use of offsystem redispatch, stating that lack of 

control over these resources could cause 

reliability problems on the originating 

transmission system. WAPA also 

believes that off-system redispatch 

would not provide the price certainty 

needed by customers because the 

redispatched megawatts will differ 

based on the transmission system 

parameters, and customers would be 

required to pay for any loop flow 

resulting from the off-system redispatch. 

1001. In its reply comments, EEI adds 

that a requirement for transmission 

providers to solicit planning redispatch 


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629See pro forma OATT section 13.5. With 

respect to SPP’s assertion that transmission owners’

affiliated generation should have no greater 

redispatch obligations than unaffiliated generation 

in RTOs, we find that relevant redispatch 

obligations in the RTO tariff and transmission 

owners’ tariffs govern this issue. See Southwest 

Power Pool, Inc., 110 FERC ¶ 61,133 at P 17 (2005) 

(rejecting proposed provisions that would have 

removed the obligation for transmission owners to 

provide planning redispatch). 

630Network customers will continue, however, to 

be obligated to make their network resources 

available to the transmission provider for reliability 

redispatch in real time. 

proposals from generators inside and 

outside their control areas would 

require that transmission personnel 

become involved in generation and 

power sales matters in violation of the 

Commission’s Standards of Conduct. 

Duke argues on reply that such an 

approach would require that third party 

generators reveal their costs to the 

transmission provider and that a means 

of estimating costs for all generators 

subject to planning redispatch would 

need to be set forth in the pro forma 

OATT. 

1002. LPPC, APPA and TAPS oppose 

any requirement that transmission 

providers redispatch their network 

customer’s resources as well as their 

own to provide planning redispatch, 

stating that this action would 

appropriate resources beyond the 

Commission’s jurisdiction, result in 

endless conflict between transmission 

providers and resource owners, and 

interfere with network customer’s use of 

their limited resources. 

Commission Determination 

1003. Order No. 888 compelled 

transmission providers to provide 

planning redispatch from their own 

resources.629 The Commission declines 

to expand that obligation to require 

transmission providers to solicit third 

party resources in order to provide 

planning redispatch. We will, however, 

require transmission providers to 

identify in the system impact study (1) 

generation resources located within the 

transmission provider’s control area, 

including its own resources, that can 

relieve the congested transmission 

facility at issue, and (2) the impact of 

each identified resource on the 

congested facilities, e.g., the generator 

shift factor. The resources identified in 

the system impact study need not be 

available to provide the redispatch. 

Customers must simply be provided 

with the set of generators that could, if 

available, make a significant 

contribution toward relieving the 

constrained facility at issue. This 

information, in addition to the 

information provided through 

congestion planning studies, will 

provide the necessary information to 

customers wishing to solicit third party 

resources to relieve congested facilities 

in order to accommodate long-term firm 

point-to-point service. We note that this 

information is readily accessible by the 

transmission provider, as it is the same 

information used to determine pro rata 

curtailments of firm resources in 

contingency situations. 

1004. In addition to identifying 

generation resources within the control 

area, the Commission also requires 

identification of resources outside the 

control area that may be able to relieve 

congested transmission facilities. To the 

extent the transmission provider is 

aware of generation resources outside of 

its control area that can relieve the 

constraint, the transmission provider 

must inform the customer of these 

resources. To be clear, this does not 

require the transmission provider to 

undertake any additional investigation 

or study to identify generation options 

located outside of the control area. To 

the extent the transmission provider has 

such information, however, it must 

provide it to the customer. 

1005. The Commission will not 

mandate the use of network customer 

resources or other third party resources 

in the provision of planning 

redispatch.630 If they choose, network 

customers and third parties may 

voluntarily provide planning redispatch 

services. A seller is free to post its price 

to relieve a specific congested 

transmission facility and its ability to 

relieve the congestion. To facilitate 

provision of such service by third 

parties, we direct transmission 

providers to modify their OASIS sites to 

allow for posting of these third party 

offers. Accordingly, we direct 

transmission providers to work in 

conjunction with NAESB to develop 

this new OASIS functionality and any 

necessary business practice standards. 

Transmission providers need not 

implement this new OASIS 

functionality and any related business 

practices until NAESB develops 

appropriate standards. 

1006. Customers may then contract in 

advance with these third parties or use 

their own resources to secure planning 

redispatch services in lieu of or in 

addition to service from the 

transmission provider. In this way, 

customers can arrange for their own 

planning redispatch through bilateral 

markets and submit plans for approval 

to their transmission provider and 

reliability coordinator. The 

arrangements must, however, be 

sufficiently detailed and coordinated 

with the transmission provider to 

ensure that reliability is maintained. 

1007. We therefore direct in this Final 

Rule that transmission providers work 

with customers to facilitate the use of 

third party generation, where available, 

in provision of planning redispatch. 

This entails review of redispatch plans 

submitted by customers, coordination 

between the transmission provider and 

reliability coordinator, and signaling 

third party generators when the 

redispatch is needed. These 

arrangements will require close 

coordination between the transmission 

provider, third party generators and 

transmission customers. The 

arrangements must be sufficiently 

detailed to allow the transmission 

provider to maintain reliability. 

Although we will not allow 

transmission providers to unreasonably 

deny customers the use of third-party 

resources to provide planning 

redispatch, it is the customers’ ultimate 

responsibility to ensure that all the 

necessary contractual and technical 

arrangements are in place to maintain 

reliability. We clarify for Entergy that 

this would allow transmission providers 

to continue to provide planning 

redispatch for network customers from 

the network customers’ resources. We 

also clarify that transmission providers 

may curtail transmission customers if a 

third-party resource fails to perform its 

contractual redispatch obligation. This 

or any other remedy for nonperformance must be specified in 

writing between the parties prior to 

commencement of the service. 

1008. For the reasons discussed below 

regarding the TDA proposal, we decline 

to adopt the bid-based redispatch model 

suggested by EPSA. In section V.C.1 of 

this Final Rule, we similarly reject 

proposals to impose LMP and 

independent control of the dispatch 

function. We believe that a bid-based 

generation market design is not 

necessary to remedy undue 

discrimination in the provision of 

transmission service. We also believe 

that our modifications to the planning 

redispatch requirement, including the 

OASIS changes directed herein and the 

requirement that transmission providers 

make available information on 

generators capable of providing 

planning redispatch, will provide 

potential customers with greater 

information about redispatch choices 

and enable greater opportunities for 

planning redispatch and comparable 

service. 


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631E.g., Powerex, Manitoba Hydro, Seattle, 

NRECA, Ameren, and E.ON. 

632E.g., Utah Municipals, Public Power Council, 

PPM, Entegra, Constellation, TransAlta and TAPS. 

633American Electric Power Service Corp, 64 

FERC ¶ 61,279 (1993) (American Electric Power). 

634 Id. at 62,976. 

635E.g., Southern, MidAmerican, Entergy, 

FirstEnergy, Ameren, Nevada Companies, E.ON, 

and South Carolina E&G. 

636E.g., EEI, Entergy, LPPC, NRECA, 

MidAmerican, Ameren, and FirstEnergy. 

637E.g., LDWP, EEI, Ameren, MidAmerican, and 

Southern. 

(C) Pricing of Planning Redispatch 

NOPR Proposal 

1009. In the NOPR, the Commission 

sought comment on which type of 

redispatch pricing would ensure 

effective use of the planning redispatch 

option. The Commission described one 

type of pricing, a formula rate, to 

include a MW quantity, the incremental 

cost of fuel at the point of delivery, and 

the decremental cost of fuel at the point 

of receipt capped at the price of fuel. 

The Commission sought further 

comment on whether it would facilitate 

planning redispatch to base calculations 

of the various costs for input into the 

formula on the difference between the 

cost of ramping up a generator at the 

point of delivery and ramping down a 

generator at the point of receipt. The 

Commission also described a redispatch 

pricing proposal to calculate redispatch 

charges monthly and charge the higher 

of actual redispatch costs or the OATT 

rate each month made by PacifiCorp in 

response to the NOI. 

Comments 

1010. While many specific comments 

were received on the pricing of planning 

redispatch service, there is little 

consensus on this subject. Several 

commenters state that pricing 

challenges associated with planning 

redispatch are difficult if not 

insurmountable.631

1011. MidAmerican and EEI argue 

that the current cap on planning 

redispatch at the costs of upgrades 

should be removed because a customer 

will always choose planning redispatch 

and the risks that redispatch costs 

exceed construction costs falls to the 

transmission provider and is either 

unrecoverable or passed on to other 

customers. 

1012. According to several 

commenters, requiring the transmission 

provider to establish a standard fee for 

planning redispatch, either on the 

overall system or on a path-by-path 

basis, would accomplish cost certainty 

for the customer and hold the 

transmission provider accountable for 

the accuracy of the studies used to 

assess redispatch requirements.632

These commenters support a 

standardized formula-rate for planning 

redispatch or a capped amount at, or 

close to, the embedded cost rate. Entegra 

and TransAlta state that the redispatch 

pricing proposal may allow 

transmission providers discretion to 

charge redispatch costs without 

providing customers a practical way to 

verify that claimed redispatch costs 

have actually been incurred. PGP states 

that the Commission should allow for 

regional differences in planning 

redispatch pricing. APPA does not 

support a departure from the current 

redispatch pricing approach, while 

Seattle states that the existing section 

13.5 is unworkable because the cost of 

planning redispatch is difficult to 

calculate for both historical and nearterm operating horizons, much less over 

a multi-year planning horizon. 

1013. EPSA and AWEA believe that 

the pricing mechanisms suggested in the 

NOPR would be open-ended and highly 

variable over the duration of the 

reservation and, thus, not meet the 

needs of customers. EPSA and AWEA 

assert that, consistent with Commission 

precedent,633 a utility must identify and 

justify its costs in excess of average 

system costs before service commences 

in a manner that meets the customer’s 

needs to charge a rate in excess of 

average system costs, i.e., some 

customers may require a firm estimate 

upfront to obtain financing while others 

may be willing to negotiate a rate based 

on estimates.634 EEI states on reply that 

the policy in American Electric Power 

related to an expansion cost rate, which 

is inapposite to redispatch costs because 

the costs of new construction are easier 

to estimate in advance than are the costs 

of planning redispatch. EEI contends 

that the planning redispatch customer’s 

interest in price certainty is not a 

sufficient basis for shifting costs to other 

customers or to the transmission 

provider. 

1014. EPSA and AWEA suggest that, 

when the cost of planning redispatch is 

estimated to exceed the transmission 

rate, the transmission provider should 

offer either: a formula rate for 

incremental redispatch costs with the 

number of hours of redispatch, the 

resources to be redispatched and the 

conditions under which redispatch 

would occur defined in advance or, an 

incremental cost rate determined at the 

time of the reservation to cover the 

reservation period that may include a 

risk adder for the transmission provider. 

Morgan Stanley argues that planning 

redispatch options should include the 

following: Redispatch priced at a market 

index; where market prices are not 

available, the price should be the 

incremental costs; full cost pricing 

should be allowed for ‘‘life of service’’

(total dollar cost for unlimited 

redispatch over the term of a contract) 

or fixed rate contracts for actual 

redispatch agreed to at the time of 

contracting; and redispatch costs 

provided from a third-party provider. 

Morgan Stanley opposes ‘‘higher of’’

pricing that would allow for monthly 

charges for redispatch costs or long-term 

firm transmission service rate. 

1015. In contrast, many transmission 

providers and EEI ask the Commission 

to allow for recovery of actual costs of 

redispatch, rather than the estimated 

costs, with the customer obligated to 

pay all costs.635 Since providing 

accurate estimates of redispatch costs 

and hours are difficult, especially with 

respect to longer-term service requests 

given the variability of fuel costs, 

transmission providers contend that 

they should not bear the risks of 

inaccurate cost estimates for a service 

that benefits only the point-to-point 

customer.636 Indianapolis Power adds 

that planning redispatch should be 

priced to discourage inefficient dispatch 

of generation. In its reply comments, 

PPM agrees that planning redispatch is 

unworkable without certainty of cost 

recovery for the transmission provider, 

but believes that with enough 

information customers can evaluate the 

risks and gain certainty required for a 

workable product. 

1016. Southern argues that the current 

pro forma OATT language unreasonably 

places the risk of uncertainty in 

estimating redispatch costs on the 

transmission provider and its native 

load customers, contrary to basic cost 

causation principles and native load 

protections in Order No. 888. Southern 

suggests that the Commission follow the 

approach in the Deseret and SPP tariffs, 

which allow for the transmission 

provider to recover its actual costs of 

redispatch. Ameren states that a 

standard per kWh fee is simpler to 

administer, but should be structured to 

recover all of the costs of planning 

redispatch, including opportunity costs. 

1017. Various commenters argue that 

the Commission should allow the 

following redispatch costs to be 

recovered: Fuel; variable operations and 

maintenance; increased maintenance 

costs due to cycling; start-up and rampdown costs; emergency purchases; costs 

of additional operating reserves; 

environmental costs; and lost 

opportunity costs.637 MidAmerican also 

argues that a transmission provider 

should be able to recover the costs of 


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638See, e.g., Florida Power & Light Co., 70 FERC 

¶ 61,158 at 61,484 (1995). 639 Id. at 61,483. 

redispatch energy purchased in 

response to a pre-schedule by a 

planning redispatch customer regardless 

of schedule changes by the customer 

and regardless of any pro rata 

curtailments affecting such customers 

due to system reliability. 

1018. EEI and Southern argue that 

customers that choose planning 

redispatch should pay the cost of 

transmission service and the cost of 

redispatch. EEI asserts that allowing 

recovery of both costs is not prohibited 

‘‘and’’ pricing because the services 

differ, as one is provided by the 

transmission system and one is 

provided by generators, and native load 

and network customers pay pro rata 

shares of reliability redispatch costs to 

relieve constraints on the system as well 

as the basic costs of transmission 

service. TAPS and TDU Systems take 

the opposite view and state that the 

Commission should require planning 

redispatch pricing consistent with the 

Commission’s ‘‘higher of’’ or ‘‘or 

pricing’’ policy. In addition, they state 

that the redispatch charges must be 

capped up front at fixed dollars and 

hours at or close to the embedded cost 

rate. 

1019. Arkansas Commission agrees 

with the PacifiCorp pricing method in 

which redispatch costs are recalculated 

monthly and customers are charged the 

higher of the redispatch cost rate or the 

monthly OATT transmission rate. TAPS 

states that this method avoids ‘‘and’’

pricing, but does not address the 

complexity or risks associated with 

determining redispatch costs over a long 

period. APPA argues that the PacifiCorp 

proposal, if applied after the fact, could 

lead to uncertainty and disruption of 

market transactions. Southern opposes 

any pricing method that caps the total 

costs that a planning redispatch 

customer would bear, including the 

PacifiCorp proposal, stating that caps 

allow the planning redispatch customer 

to shift costs to the transmission 

provider and its native load customers. 

1020. E.ON points to an inherent 

problem in planning redispatch pricing: 

Transmission providers should be kept 

whole with regard to actual real-time 

redispatch costs but customers may not 

know until after the fact that the 

planning redispatch was not economic 

for their purposes. E.ON foresees 

difficulty in allocating redispatch costs 

among multiple planning redispatch 

service customers and requests that the 

Commission adopt a specific 

methodology for calculating each 

request’s impact on the system. 

Commission Determination 

1021. Although there is no consensus 

regarding which form of pricing 

methodology is most appropriate for 

planning redispatch service, there is 

general agreement among the 

commenters that the current pricing 

rules fail to meet the needs of either 

customers or transmission providers 

and consequently fail to make planning 

redispatch an attractive means for 

customers to obtain access to the grid. 

Transmission providers and customers 

both express concern regarding the 

variability of redispatch costs. 

Customers worry that actual redispatch 

costs may greatly exceed estimates and 

thus seek cost certainty over the term of 

the service. Conversely, transmission 

providers claim that accurately 

estimating future redispatch costs for 

long duration service is extremely 

difficult. In fact, transmission providers 

state that the uncertainty in forecasting 

long-term redispatch costs is much 

greater than any uncertainty inherent in 

determining the costs of transmission 

upgrades. 

1022. The Commission has carefully 

considered these comments and agrees 

that the current method for pricing 

planning redispatch service is no longer 

just, reasonable or not unduly 

discriminatory. The Commission takes 

three principal actions to address the 

concerns of customers and transmission 

providers. 

1023. The Commission therefore 

adopts a new pricing method for 

planning redispatch service. We will no 

longer require the capping of redispatch 

costs over the term of the service at the 

costs of expansion. This change is 

inextricably linked with the change in 

the obligation to provide planning 

redispatch, i.e., the removal of the openended requirement to provide planning 

redispatch as long as it is more 

economical than transmission upgrades. 

We have shortened the planning 

redispatch obligation to apply before 

upgrades are built as a bridge product or 

to apply as part of a reassessment 

product. In prior cases, the Commission 

expressed the view that capping cost 

recovery for long-term transmission 

service at the costs of expanding the 

transmission system provides an 

incentive for transmission providers to 

undertake expansion when it is 

warranted.638 The expansion cost cap 

should not be applied to the bridge 

product because (1) upgrades will in 

fact be constructed and should be paid 

for by the customer under the ‘‘higher 

of’’ policy, and (2) an expansion cost 

cap does not serve as an incentive for 

expansion because the transmission 

provider already will have started the 

process of building transmission 

facilities for the customer who opts for 

the bridge product. If planning 

redispatch is provided as part of a 

reassessment product, the customer has 

chosen not to pay for upgrades and thus, 

the expansion cost cap cannot provide 

an incentive for transmission expansion. 

1024. We will therefore adopt a new 

pricing methodology. We believe that 

the PacifiCorp proposal described in the 

NOPR is the one that balances the 

competing concerns of transmission 

customers and transmission providers. 

Under this pricing methodology, 

customers will have the option of 

paying (1) the higher of (a) actual 

incremental costs of redispatch or (b) 

the applicable embedded cost 

transmission rate on file with the 

Commission or (2) a fixed rate for 

redispatch to be negotiated by the 

transmission provider and customer and 

subject to a cap representing the total 

fixed and variable costs of the resources 

expected to provide the service. If the 

customer selects the higher of 

incremental cost or the embedded-cost 

rate, the transmission provider shall 

calculate the costs of redispatch 

monthly and charge the higher of 

redispatch or the embedded cost rate 

each month. 

1025. We have selected a monthly 

comparison of embedded costs and 

redispatch costs on the basis of a 

number of factors. The Commission has 

rejected basing the comparison on the 

life of a long-term firm transmission 

contract.639 For administrative 

efficiency, a transmission provider 

should be allowed to close its books and 

not be subject to possible refunds or 

surcharges at the end of its billing cycle. 

The standard billing cycle in the 

industry is one month. Allowing 

transmission providers to finalize 

accounting entries will provide 

certainty to both the transmission 

provider with regard to revenue 

recovery and to the transmission 

customer with regard to cost exposure. 

We therefore find that a monthly 

comparison of embedded and 

incremental cost is appropriate. This 

method retains ‘‘higher of’’ pricing for 

customers, but does not subject 

transmission providers to open-ended 

liability for refunds and otherwise 

should make planning redispatch 

service more attractive for transmission 

providers to provide. Further, given that 

redispatch often occurs only in selected 

time periods within a year (e.g., during 


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640See Order No. 888 at 31,740. 

641See Pennsylvania Electric Company, 58 FERC 

¶ 61,278, 62,871–75, reh’g denied, 60 FERC ¶ 61,034 

(1992), aff’d sub nom. Pennsylvania Electric Co. v. 

FERC, 11 F.3d 207 (D.C. Cir. 1993); see also Entergy 

Services, Inc., 71 FERC ¶ 61,139, 61,452 (1995) 

(regarding the pricing of redispatch service, the 

Commission stated ‘‘[i]t is a well-settled matter that 

the Commission will not authorize ‘‘and’’ pricing, 

i.e., embedded cost pricing plus opportunity 

(incremental) cost pricing.’’). 

642Order No. 888A at 30,267. 

643 Florida Power & Light Co., 70 FERC ¶ 61,158 

at 61,483 (1995). 

644E.g., Nevada Companies, Community Power 

Alliance, Progress Energy, LPPC, Southern, WAPA, 

and APPA. 

645E.g., E.ON, Ameren, and APPA. 

the peak season, shoulder months, etc.), 

it is just and reasonable to allow the 

transmission provider to perform the 

higher of calculation in each month 

when the service is provided, not spread 

those costs over the entire year. 

1026. For purposes of calculating 

planning redispatch charges, 

incremental costs shall include fuel or 

purchase power costs caused by 

ramping up generator(s) at the point of 

delivery and ramping down generator(s) 

at the point of receipt. Additionally, 

where applicable, transmission 

providers may specify in customer 

service agreements other incremental 

costs for inclusion in the monthly actual 

incremental costs, including 

opportunity costs. Identification and 

derivation of these costs must be 

included in the service agreement. We 

reiterate our existing requirement that 

all information necessary to calculate 

and verify opportunity costs must be 

made available to the transmission 

customer.640 We clarify that the actual 

costs of redispatch need not be 

determined annually or at the time that 

the service agreement is executed; 

rather, actual redispatch cost should be 

determined on a monthly basis. 

1027. With respect to MidAmerican’s 

request to be able to recover the 

purchase power costs for a customer 

requiring planning redispatch, we 

reiterate that transmission providers are 

under no obligation to purchase power 

to provide planning redispatch services. 

Should the transmission provider take 

on the obligation to contract with a third 

party to provide planning redispatch at 

the customer’s request, however, the 

customer should be obligated to pay the 

purchase power costs, including any 

reservation charge for the power. The 

flow-through of purchase power costs 

must be negotiated between customers 

and transmission providers in a standalone agreement if the transmission 

provider agrees to make purchases on 

the customer’s behalf. 

1028. The Commission will not adopt 

proposals suggested by several 

transmission providers to allow for 

recovery of the embedded cost 

transmission rate and the full costs of 

redispatch. The Commission’s ‘‘higher 

of’’ pricing policy prohibits the 

transmission provider from charging 

both embedded costs and incremental 

costs such as redispatch costs.641 We 

reject EEI’s assertion that we should 

adopt such pricing because native load 

and network customers pay a load ratio 

share of redispatch costs and the 

embedded cost transmission rate. 

Planning redispatch differs from the 

reliability redispatch for which 

transmission providers are only 

obligated to provide network customers 

with ability to avoid real-time 

curtailments. Rather, planning 

redispatch is a means of creating 

additional transmission capacity,642 not 

a generation service, and thus planning 

redispatch is appropriately priced by 

applying the Commission’s ‘‘or’’ pricing 

policy. We decline to revisit that 

longstanding policy in this rulemaking. 

1029. With respect to concerns that 

the expansion cost cap was adopted to 

provide rate certainty to customers over 

the term of the service,643 we believe 

that the modified pricing policy adopted 

here will continue to provide 

appropriate certainty to customers, 

while also allowing transmission 

providers to recover just and reasonable 

costs. For customers purchasing the 

bridge product, the cost of redispatch 

will be incurred only during the initial 

term of the service agreement while new 

facilities are being constructed. During 

this term, the cost of redispatch service 

represents a legitimate cost of providing 

the service and therefore should be fully 

recoverable under the higher of policy. 

Although it is true that redispatch costs 

are difficult to project, and hence create 

uncertainty for customers, this does not 

mean that the transmission provider 

should not be allowed to recover the 

legitimate and verifiable costs of 

providing the service. Moreover, if the 

customer desires greater certainty 

regarding redispatch costs during this 

period, it can elect the fixed rate option 

discussed above and negotiate a fixed 

redispatch charge with the transmission 

provider. Once upgrades are 

constructed, however, the customer will 

receive the certainty of paying a fixed 

rate for transmission costs and, 

importantly, any expansion cost will be 

fixed at the time the initial service 

agreement is signed. Finally, for 

customers who do not select the bridge 

product because they do not want to 

fund upgrades, it would be 

unreasonable to cap the cost of 

redispatch at the cost of upgrades. In 

such an instance, the customer has 

elected to forego the price certainty that 

can be gained by funding the upgrades 

to remove the constraint that is causing 

the transmission provider to incur 

redispatch costs. 

(D) Standards of Conduct and Planning 

Redispatch 

NOPR Proposal 

1030. In the NOPR, the Commission 

requested comment on the interaction of 

planning redispatch requirements with 

the Commission’s Standards of Conduct. 

Comments 

1031. Commenters generally argue 

that the independent functioning 

requirement and the information 

sharing prohibitions under the 

Standards of Conduct are irreconcilable 

with the expanded planning redispatch 

proposal in the NOPR.644 Southern, 

TranServ and Progress Energy contend 

that the planning redispatch option 

would require close coordination and 

communication with market 

participants including the marketing or 

energy affiliate, which may create 

confidentiality and Standards of 

Conduct problems. For instance, they 

state that close coordination and sharing 

of non-public transmission and 

customer information would be required 

to determine the generating units that 

can be redispatched, the impact that 

planned and forced outages of 

redispatched generators will have on the 

availability of transmission service and 

the transmission line loadings, and the 

costs of redispatch. Some commenters 

request that the Commission adopt an 

exception to the Standards of Conduct 

to permit communication between 

transmission providers and marketing 

and energy affiliates, acting as 

generation operators, for the 

transmission provider to instruct the 

generation operator to vary its 

generator’s output.645

1032. MidAmerican suggests that it is 

unlikely that any communication 

protocols could be established that 

would both comply with the 

Commission’s current Standards of 

Conduct and permit a transmission 

provider to coordinate with its 

marketing affiliate employees to arrange 

planning redispatch. Rather, 

MidAmerican argues that the 

transmission customer would have to 

waive the Standards of Conduct to 

enable the transmission function 

employees to share the necessary 

information with their marketing 

affiliate counterparts. 


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646 18 CFR 358.5. 

647See Open-Access Same-Time Information 

System and Standards of Conduct, 83 FERC 

¶ 61,360 at 62,456 (1998), reh’g denied, 86 FERC 

¶ 61,139, reh’g denied, 87 FERC ¶ 61,382 (1999). 

1033. Other commenters argue that 

violations of the Standards of Conduct 

can be avoided by various means. PPM 

suggests that publication of redispatch 

costs similar to ancillary service costs 

and elimination of case-by-case sharing 

of information between the transmission 

provider and the generation operators 

would avoid Standards of Conduct 

issues. MidAmerican states that sole 

reliance upon bilateral agreements with 

third parties to provide planning 

redispatch would resolve the need to 

modify the Standards of Conduct. In 

their reply comments, Utah Municipals 

state that they do not believe the 

Standards of Conduct pose a barrier to 

provision of planning redispatch since 

transmission providers redispatch to 

serve their own loads currently, but that 

if so the Commission should make small 

modifications to the standards. 

Commission Determination 

1034. The Commission does not 

believe that any changes to its Standards 

of Conduct are required for transmission 

providers to implement the planning 

redispatch provisions adopted in this 

Final Rule. The information at issue, 

e.g., generation redispatch cost, is held 

by the marketing affiliate and there is no 

prohibition under our Standards of 

Conduct on the marketing affiliate 

transferring such information to the 

transmission provider. The information 

sharing prohibitions under the 

Standards of Conduct are ‘‘one way,’’

i.e., they restrict only communications 

of non-public transmission information 

from the transmission provider to the 

marketing affiliate, not vice versa. 

Therefore, the flow of information from 

marketing affiliates to transmission 

providers relating to the costs and 

availability of generation resources for 

planning redispatch is not prohibited 

under the Commission’s Standards of 

Conduct.646

1035. We next turn to the flow of 

information from the transmission 

provider to the marketing affiliate. 

Initially, in order for transmission 

providers to evaluate planning 

redispatch options, they must identify 

the impacted transmission facilities, 

e.g., flowgates, and determine the 

marketing affiliate’s generators that 

could provide redispatch over those 

facilities. Transmission providers 

already have this information to enable 

them to provide least cost reliability 

redispatch. However, transmission 

providers need not provide information 

regarding the impacted transmission 

facilities to its marketing affiliates. 

Rather, in order for transmission 

providers to evaluate the future 

availability of redispatch and estimate 

the costs of redispatch, they need only 

tell the marketing affiliate which of its 

generators would be suitable for 

redispatch, thus identifying those that 

require study. This sharing of 

information relating to the marketing 

affiliate’s generation is not prohibited by 

the Commission’s Standards of Conduct. 

1036. In addition, the transmission 

provider may also need to provide its 

marketing affiliate with transmissionrelated information from the 

transmission customer’s service request, 

such as service quantity and term, to 

determine the required duration and 

amount of the redispatch required. We 

find that such information provided 

from the transmission provider to the 

marketing affiliate is not a prohibited 

transfer of non-public information 

because such details of the transmission 

customer’s service request are available 

via OASIS. The only customer 

transmission request information not 

readily available via OASIS is the 

source and sink information.647 We see 

no need for the transmission provider to 

provide such masked source and sink 

transmission information to its 

marketing affiliate as part of this 

redispatch evaluation process. We do 

not believe that any further information 

need be provided by the transmission 

provider to their marketing affiliates to 

evaluate the generators available for 

planning redispatch and their costs. 

Accordingly, we find there is no need to 

create an exception to the Standards of 

Conduct for the sharing of this 

generation-related information and 

publicly available transmission 

customer request information. 

(E) Attributes of Conditional Firm 

NOPR Proposal 

1037. In the NOPR, the Commission 

described conditional firm service as a 

modified form of point-to-point service 

that includes non-firm service in a 

defined number of hours of the year 

when firm point-to-point service is not 

available. The Commission proposed 

that the conditional firm service 

agreement would identify the 

conditional curtailment hours and 

include an annual or monthly cap on 

those hours. The Commission further 

proposed that conditional firm service 

would be curtailed before firm uses 

until such times as the conditional 

curtailment hours were exceeded, after 

which time the service would be treated 

as firm. The curtailment priority during 

the conditional period was proposed as 

the same as secondary network service. 

The Commission proposed that 

customers using the conditional firm 

option would pay the long-term firm 

point-to-point rate. The Commission 

also proposed that conditional firm 

service qualify for rollover rights, 

provided that it meets the other rollover 

right conditions proposed in the Final 

Rule. 

(i) General Terms and Conditions 

Comments 

1038. Most commenters support 

pricing conditional firm service at the 

long-term firm OATT rate and no 

commenter suggested a different pricing 

method. Nevada Companies and 

Bonneville state that the customer 

seeking conditional firm service should 

pay the actual costs of the study 

required to provide the number of 

conditional curtailment hours. 

1039. EPSA and AWEA support the 

following components of the 

Commission’s conditional firm 

proposal: Conditional firm is available 

only to customers that first request longterm service; it would provide a year 

round, long-term product that is firm 

during all hours of the year except at 

well-defined periods when the 

transmission provider is unable to 

provide the service; and, in all hours 

that are not conditional, conditional 

firm service would be treated as any 

other firm service with the same 

curtailment priority as long-term firm 

network and point-to-point rights. 

1040. EEI proposes that conditional 

firm service be firm in periods when 

firm service is available according to 

ATC calculations and non-firm, with a 

monthly non-firm curtailment priority, 

for periods when firm ATC is not 

available. CREPC, Exelon and 

MidAmerican argue that the 

Commission should not require 

conditional firm service until all 

attributes of the service are clearly 

defined and key implementation issues 

are resolved, including modification of 

NAESB and NERC processes. NAESB 

states that the Commission can reduce 

the amount of time required to develop 

OASIS and transmission loading relief 

protocols by clearly defining the 

conditional firm service. 

1041. In its supplemental comments, 

EEI states that the Commission should 

not require all transmission providers to 

adopt terms and conditions for 

conditional firm service that are only 

workable for some systems, e.g., 

transmission providers in the Western 

Interconnection using the rated path 


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648E.g., LPPC Supplemental, PPL Supplemental, 

Williams Supplemental, Community Power 

Alliance Supplemental, Entergy Supplemental, and 

Southern Supplemental. 

649Potential New Wholesale Transmission 

Services, Notice of Final Agenda for Technical 

Workshop, 70 FR 12865 (Mar. 16, 2005). 

650E.g., Bonneville Workshop Comments at 1–2 

(April 13, 2005) (stating that Bonneville believes the 

result of the workshop ‘‘will be the development of 

one or more new transmission products.’’), TAPS 

Workshop Comments at 2 (April 13, 2005) 

(suggesting that the Commission should invite and 

consider proposals by individual utilities rather 

than act by rulemaking). 

651 In the NOPR, the Commission noted 

PacifiCorp’s 2002 modifications to partial interim 

service. See NOPR at P 319 n.298. PacifiCorp’s 

service is similar to that proposed by EEI with the 

exception that customers are charged a pro rated 

long-term firm rate. 

652E.g., Imperial, Duke, Progress Energy, 

MidAmerican, PNM–TNMP, Southern, and EEI. 

methodology compared to many in the 

Eastern Interconnection using a flowbased methodology; rather, the 

Commission should allow flexibility in 

the offer of conditional firm service so 

that transmission providers are not 

foreclosed from offering the service. 

1042. Several commenters state that 

transmission providers and customers 

collectively should design the 

conditional firm service that best 

accommodates their respective needs.648

In supplemental comments, Bonneville 

states that the transmission provider, 

not the customer, must determine the 

conditions to offer in response to a 

given request. Bonneville also requests 

that the Commission clarify that there 

would be no separate queue for 

conditional firm service. 

Commission Determination 

1043. The Commission adopts the 

conditional firm option as a modified 

form of long-term firm point-to-point 

service that includes less-than-firm 

service in a defined number of hours of 

the year or during defined system 

conditions when firm point-to-point 

service is not available. The service can 

be curtailed solely for reliability reasons 

during the defined system conditions or 

defined number of hours. We reject 

EEI’s suggestion to use a monthly nonfirm curtailment because it would allow 

for curtailment of the conditional 

service for economic reasons. 

1044. In this Final Rule, we define the 

minimum attributes of the conditional 

firm option rather than allow individual 

transmission providers to develop any 

form of service that could conceivably 

be labeled conditional firm service. The 

Commission has been considering a 

conditional firm product and has been 

discussing it with the industry for some 

time. In early 2005, the Commission 

held a technical workshop to: 

Work with market participants to develop 

clear definitions for additional wholesale 

electric transmission services, e.g., 

conditional firm transmission service, 

develop applicable pro forma tariff language 

that could be included in public utilities’

open access transmission tariffs and address 

attendant issues.649

Although commenters in that 

proceeding stated that the Commission 

need not require new services in 

transmission providers’ OATTs because 

they would be voluntarily developed,650

no individual transmission provider 

developed new services in response to 

the workshop. In fact, seemingly, only 

one transmission provider in the Eastern 

or Western Interconnection offers a 

service that is similar to the conditional 

firm service adopted in this Final 

Rule.651

1045. Since the issuance of the NOPR, 

the Commission has provided the 

industry with three formal opportunities 

to provide comments on 

implementation of the conditional firm 

option. The Commission held a 

technical conference on implementation 

issues after issuance of the NOPR and 

held many informal technical 

discussions with industry 

representatives. We have taken these 

steps in order to make the most 

reasoned decision concerning the 

minimum attributes of the conditional 

firm option. These conferences and 

workshops have been helpful and have 

informed our decision on the minimum 

attributes of conditional firm service. As 

noted herein, although we are 

establishing certain minimum attributes, 

we also allow for some measure of 

flexibility in provision of the service. 

We will not, however, approve 

conditional firm as a concept only. 

Given our past experience, this would 

provide little benefit to customers 

seeking to use the service and no 

certainty to transmission providers 

seeking to comply with our regulations. 

1046. Further, as discussed in more 

detail below, we disagree that NERC 

must modify its processes in order to 

allow transmission providers to 

implement this product. However, we 

will allow for a sufficient period of time 

for development of business practices 

and tracking mechanisms to implement 

the product. We recognize that there 

may be some regional variation in the 

way transmission providers approach 

the provision of conditional firm service 

beyond the minimum attributes that we 

establish in this Final Rule. Thus, we do 

not direct that transmission providers 

work with NAESB to develop business 

practices for implementation of the 

conditional firm service. Rather, we 

direct transmission providers located in 

the same region to coordinate such 

development among themselves. We 

also encourage participation of nonpublic utility transmission providers in 

the region and interested transmission 

customers in the development of these 

business practices. Public utility 

transmission providers should make 

efforts to include these interested 

parties in their regional coordination 

efforts. We direct transmission 

providers to implement these 

mechanisms and business practices 

within 180 days after the publication of 

this Final Rule in the Federal Register. 

1047. The Commission adopts the 

proposal in the NOPR that customers 

using the conditional firm service pay 

the long-term firm point-to-point rate. 

We will not allow complete flexibility 

in defining the conditional firm option 

as suggested by EEI because such an 

option could provide a substantially 

lower quality service for which 

transmission providers would be able to 

recover the long-term firm rate. We also 

reject EEI’s proposal that the service be 

a mix of firm and non-firm periods. We 

envision the conditional firm option as 

one in which firm service is available 

most of the period of a year. EEI seems 

concerned about tailoring the product to 

situations where congestion is so acute 

that the ‘‘conditions’’ require frequent 

interruptions. We do not believe this 

concern is well founded. Because a 

conditional firm customer is obligated 

to pay the long-term firm point-to-point 

rate, we assume that few, if any, 

customers would accept the service in 

circumstances where the interruptions 

(or ‘‘conditions’’) are so frequent or 

pervasive to make the service 

unattractive. 

1048. Finally, we clarify for 

Bonneville that customers seeking the 

conditional firm option must first 

request long-term firm service. When 

ATC is unavailable, the transmission 

provider must study the conditional 

firm option at the customer’s request. 

There is no separate queue for the 

conditional firm option. 

(ii) Specified System Conditions and 

Conditional Hours 

Comments 

1049. Several transmission providers 

state that they cannot accurately predict 

the conditional curtailment hours 

because there are too many variables to 

consider and ATC analysis does not 

provide this level of granularity.652

These commenters contend that load 

flow modeling for a wide range of 


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653E.g., Barrick Supplemental, Bonneville 

Supplemental, BP Energy Supplemental, and EPSA 

and AWEA Supplemental. 

654E.g., AWEA, EPSA, Project for Sustainable 

FERC Energy Policy, Santee Cooper, Seattle, 

Entergy, and LPPC. 

655E.g., Santee Cooper, Seattle, Entergy, LPPC, 

and Nevada Supplemental. 

possible system conditions required to 

estimate the conditional curtailment 

hours would be complex, timeconsuming and costly. Given this 

concern, Southern, PNM–TNMP, and 

MidAmerican state that any conditional 

firm service should be subject to a 

‘‘reasonable efforts’’ standard and not 

represent a guarantee of service or a 

binding estimate of conditional 

curtailment hours from the transmission 

provider. Progress Energy states that it 

would be difficult to determine a 

specific number of hours that firm 

service is available, given that the 

industry uses seasonal models. Ameren 

states that the conditional curtailment 

hours should be spelled out in the 

transmission service agreement. 

1050. Several commenters state that 

the transmission provider should 

provide customers a choice between 

defined system conditions and 

conditional curtailment hours.653 In 

supplemental comments, EPSA and 

AWEA state that neither option should 

be arbitrarily excluded; rather, they 

argue that transmission providers 

should consult with each customer in 

determining the defined conditions that 

could form the basis of the conditional 

firm service. EPSA and AWEA propose 

that conditional firm should be firm 

during all hours of the year except in 

those hours in which a defined 

contingency occurs, and the 

transmission provider is actually unable 

to provide service. EPSA and AWEA 

also propose that the system impact 

study should describe the reliability 

contingency and the transmission 

service agreement should clearly define 

the contingency. 

1051. EPSA and AWEA state that 

conditional firm should only be 

curtailed after all non-firm services are 

curtailed on the same constrained path 

during the period of the defined 

contingency. Finally, AWEA and EPSA 

state that transmission providers must 

maintain the committed capacity subject 

to the defined contingency only, reflect 

capacity commitments for conditional 

firm service in their ATC calculations, 

and be prevented from further curtailing 

conditional firm service due to load 

growth after the execution of the initial 

service agreement. 

1052. AWEA proposes that if a service 

agreement specifies conditional 

curtailment hours, the transmission 

provider must provide firm service 

except in the curtailable hours defined 

in the service agreement and the service 

must be treated as firm unless the 

transmission provider is actually 

required to curtail transactions to meet 

reliability requirements and all non-firm 

transactions have been curtailed. Once 

the transmission provider has reached 

the annual cap on curtailable hours, 

AWEA argues the customer’s service 

should convert to traditional firm 

service for the remainder of that annual 

period. 

1053. Utah Municipals reply that 

transmission providers should be bound 

by their calculations of the availability 

of firm service, even if the firm service 

is not available year-round. 

1054. FirstEnergy and Nevada 

Companies state that monthly caps, as 

opposed to annual caps of curtailment 

hours, would be preferable because they 

provide more information to the 

customer and are more appropriate for 

transmission systems with mostly 

seasonal constraints. According to 

Nevada Companies, a curtailment based 

upon the maximum number of hours 

per year, without taking into account 

the specific times or conditions for 

those curtailments, would be 

unworkable in the context of a seasonal 

peak system, such as exists with Nevada 

Companies. 

1055. Several commenters support a 

variation on conditional firm service 

that would allow a transmission 

provider to specify either the 

transmission facilities/elements that 

may become constrained or the 

operating conditions that will result in 

curtailments of a particular conditional 

firm service.654 Many of these 

commenters propose a defined system 

condition as the trigger for non-firm 

curtailment of the service rather than 

the use of conditional curtailment 

hours.655 Entergy and LPPC propose 

that such curtailments have the same 

priority as secondary network service. 

Entergy contends that this service 

would be superior to the conditional 

firm service described in the NOPR 

because it would be more comparable 

with the service transmission providers 

make available to network customers 

and would minimize the risk to other 

customers who might otherwise bear the 

cost of inaccurate conditional 

curtailment hours, as well as disputes 

between the transmission provider and 

the transmission customer regarding the 

number of conditional curtailment 

hours. Seattle and Santee Cooper 

suggest that defining the limitations on 

the service based on operating 

conditions, with non-binding estimates 

of hours of curtailment, would lead to 

more effective and reliable operation of 

the transmission system that is 

consistent with regional requirements. 

1056. In supplemental comments, 

Bonneville asserts that the transmission 

provider should have the option of 

offering conditional curtailment hours 

or specified system conditions in order 

that the transmission provider can make 

a prudent choice based on available 

historical system data. 

1057. In supplemental comments, 

TAPS argues that conditional firm 

service should be limited to 100 hours 

per year of conditional curtailment, 

subject to curtailment on the same basis 

as firm service beyond those hours, and 

made available to and integrated with 

network customers. In TAPS view, this 

would result in a more efficient use of 

the grid, provide customers sufficient 

certainty to sign long-term power 

purchase contracts and promote 

transmission construction. TAPS also 

believes that the customer should have 

the option of expressing the curtailment 

restriction on the basis of specified 

system conditions in the 100-hour 

range. 

1058. In its supplemental comments, 

Entergy suggests that the Commission 

allow more flexibility between the 

contracting parties to identify the 

conditional nature of the service, i.e., 

the Commission should not prescribe 

parameters of the conditional period 

that may ignore real-time conditions on 

the transmission provider’s system that 

require a curtailment. 

1059. EEI, Duke, and PNM–TNMP 

object, in their supplemental comments, 

to specifying system conditions or the 

maximum number of curtailment hours 

per year, stating that requiring either 

would be incompatible with current 

curtailment procedures and unfairly 

shift risks of curtailment to other firm 

customers. EEI, Progress Energy and 

Duke argue that the service should be 

curtailable during a particular season, 

month or other defined period to 

provide more certainty to the 

transmission customer and the 

transmission provider as to when the 

service is subject to curtailment. 

1060. With regard to modeling 

methods for estimating the conditional 

curtailment hours, EEI asks the 

Commission not to require the 

transmission provider to use a specific 

methodology to evaluate whether it can 

provide conditional firm service. 

Bonneville argues that transmission 

providers need flexibility to modify 

their ATC methodologies to 

appropriately model the new service 

and avoid planning obligations to firm 


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656E.g., Bonneville, AWEA Reply, and EPSA 

Reply. 

up the conditional curtailment hours of 

a conditional firm reservation. Nevada 

Companies suggest that the transmission 

provider use the appropriate seasonal 

operating case with updated projections 

to determine the amount of requested 

service that can be provided without 

violating reliability criteria. 

1061. Ameren argues that when a 

transmission provider models system 

contingency events, the events are not 

interchangeable with a number of hours. 

According to Ameren, the two 

measurements will produce different 

impacts for the transmission system, 

and the transmission provider should 

not be required to make both options 

available at the customer’s option. LPPC 

and Public Power Council state that 

transmission providers should not be 

required to limit the number of 

curtailments on a monthly or yearly 

basis because of the inherent 

unpredictability of future transmission 

constraints. APPA states that using 

curtailment based on a specified 

number of hours will cause the 

transmission provider to overestimate 

the number of curtailment hours. 

1062. NRECA believes that the 

Commission should allow for regional 

flexibility in the determination of the 

parameters of the service and 

transmission providers should have 

maximum flexibility to set conditions 

that use conservative assumptions (e.g., 

based on the driest weeks of the year, 

summer or winter peak period 

constraints). NRECA believes such 

service should be conditioned on 

operating conditions as well as with 

reference to a number of times of 

interruption. In contrast, MISO supports 

the election of a consistent method of 

curtailment applied to all customers, in 

order to make the service easier to 

implement. 

1063. Powerex states that conditional 

firm service should be offered only on 

paths where curtailment to existing 

long-term customers is not expected to 

occur. 

Commission Determination 

1064. The Commission requires that, 

when conducting the system impact 

study for the conditional firm option, 

the transmission provider shall identify: 

(1) The specific system condition(s) 

when conditional curtailment may 

apply; and (2) the annual number of 

hours when conditional curtailment 

may apply. A customer must select 

either conditions or hours for 

incorporation into its conditional firm 

service agreement. 

1065. We require the offer of specific 

system conditions during which 

conditional curtailment may apply for 

several reasons. Specified system 

conditions give certainty to the 

customer that it will only be 

conditionally curtailed when forecasted 

reliability problems actually occur. 

Transmission providers benefit from 

this option because they can point to 

specific constraints on their system and 

implement a curtailment plan when 

those transmission elements are 

constrained. Additionally, designation 

of specific system conditions may allow 

for a better fit of the conditional firm 

service to a specific transmission 

provider’s system. Consider the example 

of firm service that is not available on 

a specific system because a transmission 

line is taken out of service for 

maintenance about two weeks a year. 

The designation of this line as the 

specific condition for conditional firm 

service would allow the transmission 

provider to provide firm service without 

having to worry if the maintenance on 

the line takes an extra week. The 

conditional firm customer has fewer 

concerns about undue discrimination by 

the transmission provider and could 

benefit from maintenance on the line 

that was finished one week early. 

Additionally, we note that many 

commenters representing transmission 

providers and customers support this 

approach. 

1066. We will require specificity of 

system conditions. Acceptable system 

conditions include, but are not limited 

to, designation of limiting transmission 

elements, such as a transmission line, 

substation or flowgate. We do not 

believe, however, that designation of 

system load levels, standing alone, 

would qualify as an acceptable system 

condition. Rather, load levels would 

have to be linked to a specific constraint 

or transmission element that is 

associated with the request for service, 

e.g., load levels in a constrained load 

pocket. Otherwise, the system load level 

would not be specific to the part of the 

system over which service is requested 

and, hence, have no necessary relation 

to the problems, if any, created by the 

service being requested. Furthermore, 

because most system loads experience 

load growth every year, conditional 

curtailments would necessarily increase 

over a multi-year conditional firm 

service term. 

1067. We recognize that modeling of 

the conditional curtailment hours 

entails difficulties beyond those 

encountered in modeling ATC. To 

address these difficulties we are 

allowing flexibility in determining the 

number of hours. We clarify that we will 

not require a standardized method of 

modeling the conditional curtailment 

hours. We also note that the 

Commission’s examination of modeling 

methods in the NOPR was not meant to 

propose one method over another; 

rather, it was meant to examine possible 

ways to determine a number of 

conditional curtailment hours to 

encourage dialog on the issue. 

Additionally, we will allow 

transmission providers to add a risk 

factor to their calculation of annual 

curtailment hours to account for 

forecasting risks. Further, we note that 

our adoption of the conditional bridge 

and reassessment products, detailed 

above, address modeling difficulties by 

limiting the number of years that a 

transmission provider must model in 

determining both the number of hours 

and future system conditions. Moreover, 

we clarify that if the customer selects 

the annual hourly cap option, the 

transmission provider has the flexibility 

to conditionally curtail the customer for 

any reliability reason during those 

hours, including but not limited to, the 

system condition(s) identified in the 

system impact study. Without this 

flexibility the hourly cap option and the 

specific system condition option would 

be indistinguishable with a cap on the 

number of hours that the system 

conditions interruption could occur. 

1068. We will require annual caps on 

the number of hours because calculating 

an annual cap entails less risk for the 

transmission provider and its existing 

firm customers than monthly or 

seasonal caps. While we will not require 

monthly or seasonal caps, we encourage 

transmission providers to offer them if 

they can overcome modeling barriers 

because monthly or seasonal caps give 

more certainty to customers about the 

particular aspects of their service. 

Though we allow for flexibility in 

modeling and determining the number 

of conditional curtailment hours for a 

particular service request, we believe 

that this will have a minimal impact on 

conditional firm customers. 

Transmission providers will be allowed 

to curtail only for reliability purposes 

and conditional firm customers during 

conditional curtailment hours will be 

curtailed only after all point-to-point 

non-firm customers have been curtailed. 

(iii) Conditional Curtailment Priority 

Comments 

1069. Some commenters agree with 

the Commission’s proposal that 

conditional firm service should have 

secondary network curtailment priority 

during conditional curtailment hours,656

while others disagree. Bonneville 

supports the use of the secondary 


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657Citing Order No. 888 at 31,750. 

658E.g., EEI, EPSA, TranServ, Bonneville, 

Constellation and Seattle Reply. 659See pro forma OATT section 14.7. 

network curtailment priority arguing 

that customers will value the service 

more with the secondary network 

priority, thus increasing the viability of 

conditional firm service as an 

alternative to transmission upgrades. 

EPSA and AWEA argue that conditional 

firm service during conditional 

curtailment hours should be curtailed 

after all non-firm uses. In their reply 

comments, TDU Systems oppose EPSA 

and AWEA’s position, arguing that 

secondary network service should have 

at least as high a priority as conditional 

firm service. In contrast, EEI argues that 

setting the curtailment priority equal to 

secondary network service would 

adversely impact the reliability of firm 

service by reducing real-time redispatch 

options and contradict Order No. 888 

precedent that provides priority nonfirm service only for network customers 

that pay a load ratio share of system 

costs.657 If conditional firm service is 

implemented, Powerex states that 

transmission providers should provide 

data and evidence demonstrating that 

the rights of existing long-term firm 

customers will be protected. EEI takes 

issue with the Commission’s proposal to 

grant conditional firm customers 

priority non-firm service during 

conditional curtailment hours because 

they would pay for long-term use of the 

grid, stating that all long-term point-topoint customers pay for service on a 

long-term basis but, unlike network 

customers, they do not get priority nonfirm service. 

1070. Commenters address 

implementation issues related to the 

Commission’s right of first refusal, 

tagging, tracking, and curtailment 

priority proposals, as well as other 

implementation issues implicated in the 

conditional firm service. Manitoba 

Hydro, Bonneville and Seattle support 

the Commission’s proposal that 

conditional firm service would qualify 

for right of first refusal when firm 

service becomes available. Several 

commenters believe that the 

Commission’s proposal with regard to 

right of first refusal should be refined to 

allow automatic assignment to 

conditional firm customers of firm 

capacity as it becomes available in the 

short term.658 Bonneville asserts that 

prior to implementation of the new 

service the industry must work with 

NAESB to develop a communications 

protocol to either employ automatic 

assignment or right of first refusal. 

1071. Entergy and Exelon state that 

the standards for implementing 

transmission loading relief, including 

the NERC’s Interchange Distribution 

Calculator (IDC), would need 

modification to allow for curtailment. 

Specifically, Entergy contends that the 

Commission should allow time for the 

IDC to be modified to specify a different 

curtailment priority for the same 

transaction depending on the identity of 

the constraining element. Imperial states 

that it may take over a year to develop 

computer software to correctly handle 

new curtailment priorities during an 

emergency. Bonneville disagrees and 

states that conditional firm service does 

not present unique issues with respect 

to curtailment and that it would be 

curtailable during real time like 

secondary network service. 

1072. EEI states that the conditional 

firm service as currently proposed 

would conflict with tagging protocols 

and NERC criteria because there is 

currently no way to tag service as both 

firm and non-firm. EEI states that, if 

conditional firm service is subject to 

curtailment during a specific period, the 

tag can identify those periods and 

curtailments will be implemented in 

conditional periods and non-conditional 

periods in accordance with those tags. 

However, if conditional service is 

curtailable in a certain number of hours, 

or when specific conditions occur, the 

tag cannot be rewritten in a way that 

will provide for curtailment without 

personal involvement of balancing 

authority operators, which could lead to 

increased curtailments of firm 

transmission customers. 

1073. Xcel states that limiting 

curtailments to a specified number of 

hours per year could result in 

conditional firm service having greater 

value than firm, while strictly adhering 

to a maximum number of curtailment 

hours could potentially conflict with the 

reliability standards in section 215 of 

the FPA. NRECA argues that conditional 

firm service should be subject to pro 

rata curtailment with all other firm 

users during non-conditional times. 

Commission Determination 

1074. We adopt a secondary network 

curtailment priority to apply for the 

hours or specific system conditions 

when conditional firm service is 

conditional. During non-conditional 

periods, conditional firm service is 

subject to pro rata curtailment 

consistent with curtailment of other 

long-term firm service. Thus, secondary 

network service and conditional firm 

service when it is conditional will share 

the same curtailment priority. Also, 

there is no conflict with reliability 

standards because conditional firm 

service will be subject to pro rata 

curtailment with all other firm uses of 

the system once conditional curtailment 

hours, if that is the option selected, are 

exhausted. 

1075. The secondary network 

curtailment priority is appropriate 

because the customer is paying the longterm firm point-to-point rate and thus 

should receive the highest non-firm 

curtailment priority during the 

conditional curtailment hours or during 

specified system conditions. Adoption 

of this curtailment priority overcomes 

what could otherwise be significant 

implementation hurdles. It allows for 

implementation of the service without 

changes to existing NERC TLR practices. 

NERC and members of the industry 

need not undertake the time-consuming 

and expensive process of establishing a 

new curtailment priority that is between 

firm and non-firm service as some 

commenters requested. Use of this 

curtailment priority also avoids 

attendant decisions relating to the 

method of curtailment that should 

apply, i.e., pro rata or transactional 

curtailment, for a quasi-firm curtailment 

priority. It is also consistent with 

existing interruption provisions of the 

pro forma OATT which provide that 

secondary service cannot be interrupted 

for economic reasons.659 This is 

consistent with our determination that 

conditional firm service when it is 

conditional is curtailable only to 

maintain reliable operation of the 

transmission system. 

1076. We reject EEI’s argument that 

the curtailment priority for conditional 

firm service is inconsistent with 

Commission precedent regarding 

priority non-firm service only for 

network customers. EEI’s argument is 

inapposite. Long-term firm point-topoint customers taking fully firm service 

without the conditional firm option do 

not need access to priority non-firm 

service as EEI suggests. They have 

assurance that their service will not be 

interrupted for economic reasons and 

will only be curtailed on a comparable 

basis with network service. This would 

not be the case for conditional firm 

customers. We also find that EEI has 

failed to explain the connection 

between the conditional firm 

transmission service and the availability 

of reliability redispatch options, i.e., 

generators on its system that can ramp 

up or down in response to a 

curtailment. We reject Powerex’s 

request that transmission providers be 

required to show that existing long-term 

rights are protected. Each addition of a 

new long-term firm transaction impacts 


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660For example, in the Eastern Interconnection, 

tags can be changed up to 35 minutes before the 

hour in which a TLR event is scheduled. See NERC 

Standard IRO–006–3, Transmission Loading Relief 

Procedures—Eastern Interconnection, section 6.2 

(Communications and Timing Requirements) at 23–

25 (August 2, 2006). 

661E.g., AWEA, EPSA, Manitoba Hydro, 

Bonneville, TranServ, Seattle, and Utah Municipals 

Reply. 

662E.g., EEI, FirstEnergy, Ameren, SPP, and TDU 

Systems Reply. 

the rights of existing firm customers to 

some extent. 

1077. We disagree with commenters’

suggestion that the NERC IDC must be 

changed to accommodate conditional 

firm service. We reiterate that we are not 

creating a new curtailment priority in 

this Final Rule. We also disagree that 

new tags that combine a firm and nonfirm priority must be developed in order 

to implement the conditional firm 

option. The curtailment priority in a tag 

can be changed ahead of the operating 

hour based on a near-term forecast of 

system conditions.660 We are cognizant 

that daily and hourly operations to 

change the tags for conditional firm 

customers likely involve the need for 

control room coordination and 

development of an appropriate tracking 

process. As the Commission described 

in the NOPR, new tracking and tagging 

business practices for this service must 

be developed by each transmission 

provider. Thus, we are allowing a 

sufficient period for the development of 

these business practices, i.e., 180 days 

from the date of publication of this Final 

Rule in the Federal Register. As 

directed above, transmission providers 

must coordinate with other transmission 

providers in their regions to develop 

these tracking and tagging business 

practices. 

1078. Finally, we address requests to 

allow for automatic assignment of shortterm firm point-to-point service to 

conditional firm customers. We agree 

that transmission providers must take 

into account the conditional firm 

service in evaluating the availability of 

short-term firm service. Because 

conditional firm is a long-term firm use 

of the system, it should not be 

interrupted prior to short-term firm 

service. However, short-term firm 

service reserved prior to the reservation 

of conditional firm service should 

maintain priority over conditional firm 

service in the periods when conditional 

firm service is conditional, i.e., when 

specified system conditions exist or 

conditional curtailment hours apply. 

Because the assignment proposal meets 

both of these objectives, we direct 

transmission providers to assign shortterm firm service to conditional firm 

customers as the service becomes 

available. Accordingly, we direct 

transmission providers to work with 

NAESB to develop the appropriate 

communications protocols to implement 

this attribute of conditional firm service. 

Transmission providers need not 

implement this requirement until 

NAESB develops appropriate 

communications protocols. 

(iv) Rollover Rights 

Comments 

1079. Several commenters support the 

Commission’s proposal that conditional 

firm service would qualify for rollover 

rights.661 Manitoba Hydro, Bonneville 

and Seattle state that rollover rights are 

appropriate where the transmission 

provider does not have an obligation to 

plan for service to the conditional firm 

customer during the conditional 

curtailment hours. Bonneville adds that, 

in rolling over conditional firm service, 

the transmission service agreement 

should allow for no more than the same 

number of conditional curtailment 

hours than in the original service 

agreement and provide for fewer hours 

of curtailment if system conditions 

provide for more firm service. If 

conditional firm service is used as an 

interim product until transmission is 

built, APPA contends that rollover 

rights would be appropriate. 

1080. Others argue that rollover rights 

for conditional firm service are 

inappropriate.662 These commenters do 

not support the granting of rollover 

rights, nor do they support the 

designation of conditional firm service 

as long-term service. In order to 

accommodate conditional firm rollover 

rights, FirstEnergy contends that the 

transmission provider would be 

required to model a number of off-peak 

load flow cases and provide system 

reinforcements. Ameren states that the 

number of hours that the service will be 

available at some future date after the 

contract expires will not be known at 

the time the initial contract is executed. 

EEI adds that estimating conditional 

curtailment hours for 10 years of service 

is an impossible task. MISO states that 

rollover rights would add more 

complexity to the AFC/ATC calculation 

process and competition queues. 

Entergy and EEI state that, while 

subsequent firm transmission service 

should not be placed ahead of the 

conditional firm service, it is 

appropriate at the time of a rollover 

request, and perhaps more frequently, to 

allow the transmission provider to 

update the conditional firm service 

parameters in order to take into account 

load growth and changes in load for 

prior services. 

Commission Determination 

1081. The Commission finds that 

rollover rights are appropriate for pointto-point service that is provided using 

planning redispatch or conditional firm 

options and would otherwise be eligible 

for rollover rights. The following 

discussion addresses only rollover 

rights for service that is paired with a 

transmission provider’s biennial 

reassessment right. While the 

Commission agrees with commenters 

that subsequent firm transmission 

service requests should not be placed 

ahead of the conditional firm service, 

we note above our concerns with the 

modeling requirements and reliability 

impacts of an ongoing service that relies 

upon unchanging curtailment 

conditions or redispatch requirements. 

The biennial assessment right, 

discussed above, addresses the concern 

expressed by EEI that transmission 

providers cannot accurately determine 

conditional curtailment hours or 

estimate redispatch costs for a ten-year 

service. The biennial review in 

conjunction with rollover rights allows 

the transmission provider to update the 

parameters of the service in order to 

maintain reliable operations and allows 

customers to keep their place in the 

queue ahead of other customers seeking 

conditional firm, planning redispatch 

options, or other firm services. 

1082. Rollover rights for the 

reassessment product can provide 

significant value to the conditional firm 

customer. A conditional firm customer 

opting to roll over will retain priority 

claim to the portion of its service that 

is firm. For example, if a five-year 

conditional firm service initially has a 

100-hour annual cap on curtailments, 

but the cap is later reassessed at 150 

hours, the rollover right would continue 

to give the customer first call on all but 

the 150 hours as against all other 

subsequent requests for firm service. 

1083. We note that a customer taking 

conditional firm or planning redispatch 

options as part of a five-year point-topoint service must declare its intent to 

roll the service over in the fourth year 

of service, coincident with the second 

biennial review. Thus, we task 

transmission providers and customers, 

in negotiating their service agreement, 

with coordinating the timing of the 

biennial review with the deadline for 

declaring rollover intent. Specifically, 

customers deciding whether to renew 

their service should have information 

on additional conditions on the service 

or additional estimated redispatch costs 


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663Such a review would occur in the first year 

of a rolled over service if the initial service term 

was for five years. 

664E.g., Entergy Supplemental, Southern 

Supplemental, MISO Supplemental, Community 

Power Alliance Supplemental, and Powerex 

Supplemental. 

665E.g., AWEA, EPSA, TAPS, APPA, Utah 

Municipals Reply, and Barrick Reply. 

666E.g., Bonneville Supplemental, TDU Systems 

Supplemental, PPL Supplemental, and BP Energy 

Supplemental. 

667E.g., NRECA, TDU Systems, TAPS, and Utah 

Municipals Reply. 

668E.g., APPA Supplemental, EPSA and AWEA 

Supplemental. 669Wisconsin Public Power Inc. v. Wisconsin 

Public Service Corp., 84 FERC ¶ 61,120 at 61,660 

(1998) (WPPI). 

at least 30 days prior to the relevant 

rollover deadline. 

1084. Additionally, because the 

biennial review provides the 

transmission provider with the ability to 

plan for and maintain system reliability, 

we will not allow the rollover right to 

infringe upon this review. Thus, we 

direct that the transmission provider has 

a right to review the conditions or 

redispatch requirements at the end of 

the first year of a service that has been 

rolled over, i.e., year six of service, as 

consistent with a biennial review of 

service.663

(v) Use of Conditional Firm Options in 

Designating Network Resources 

Comments 

1085. Several commenters state that 

the Commission should not modify 

current OATT requirements for 

designating network resources to 

include resources delivered using 

conditional firm service; otherwise, 

reliability would be threatened because 

network customers could lean on the 

system during conditional periods.664

They oppose allowing a resource taking 

conditional firm service to qualify as a 

network resource when the associated 

resource is imported by a network 

customer from an adjacent system. EEI 

and Duke agree with the Commission’s 

NOPR proposal that conditional firm 

service should not be available to 

network customers and further assert 

that a product that includes a non-firm 

portion is inappropriate for a loadfollowing service like network service. 

EEI asserts that because the Commission 

requires that network resources be 

deliverable on a non-curtailable basis, 

resources using conditional firm service 

cannot be designated as a network 

resource until the maximum conditional 

curtailment hours have been reached. 

EEI and Duke contend that establishing 

a defined period of curtailment for 

conditional firm service, either seasonal, 

monthly, or specific dates, eliminates 

issues with respect to the designation of 

network resources because a resource 

using conditional firm service would be 

eligible for designation for the part of 

the year when the service was defined 

as firm. In its reply comments, Duke 

states that it cannot reliably operate its 

system if it is required to serve 

unplanned load when a network 

resource is undeliverable due to 

curtailment of conditional firm service. 

1086. Other commenters assert that 

the Commission should create an 

exception to allow designation of 

network resources that use conditional 

firm service.665 AWEA adds that 

resources should not lose their 

designation when transactions are 

curtailed pursuant to conditional firm 

service because this is not the way 

similar resources with special 

protection systems are treated. Several 

commenters state that conditional firm 

service should qualify as a network 

resource when the associated resource is 

imported by a network customer.666 BP 

Energy adds that more coordination 

between the two systems with respect to 

specifying the set of conditions or 

specific set of hours is required. 

1087. Some commenters state that 

conditional firm service should be made 

available to network customers because 

conditional firm service may trump the 

provision or scheduling of secondary 

network service and because network 

customers should have service that is at 

a minimum equivalent with point-topoint service.667 These commenters 

suggest that the Commission could 

permit network customers to designate 

a conditional network resource that 

would be a firm resource for the hours 

when a comparable conditional firm 

point-to-point service is firm. In 

supplemental comments, NRECA and 

TAPS argue that ‘‘on-system’’ LSEs 

should be allowed to designate a 

network resource where transmission is 

fully firm for all but the limited time 

each year, e.g., to 100 hours or less, and 

‘‘off-system’’ LSEs should be allowed to 

treat a network resource supported by 

conditional firm service as a resource on 

the host system where it takes network 

service. NRECA believes that if the 

criteria for both network service 

resource designations and for the 

proposed conditional firm service are 

based on the physical, engineering 

characteristics of the transmission 

system, the network customer should be 

able to designate the resource as 

deliverable to load on a non-curtailable 

basis, except for the specified 

conditions. 

1088. In its reply comments, 

Bonneville states that since secondary 

network service cannot be purchased on 

a long-term basis, the Commission 

should evaluate whether the design and 

implementation challenges of creating a 

conditional firm service for network 

customers can be overcome. Bonneville 

also states that other options such as 

seasonal firm and long-term reservation 

of secondary network service should be 

explored in order to allow network 

customers similar access to monthly 

ATC. 

1089. Nevada Companies state that 

network customers have load service 

obligations and should always have 

unconditional firm service, without 

exception. However, Nevada Companies 

state that network customers could 

benefit from a service similar to 

conditional firm service. According to 

Nevada Companies, if a network 

customer desires to deliver its resources 

to a point of receipt that is not available 

all seasons of the year, it could procure 

firm transmission capacity that is 

available on a seasonal basis for the 

delivery of a network resource. 

1090. Some commenters state that 

network customers should be permitted 

to designate as network resources third 

party power supplies that are supported 

by the supplier’s conditional firm 

reservation.668 In supplemental 

comments, Xcel states that it does not 

oppose allowing conditional firm to 

qualify as a network resource, but it 

should be clear that the service is an 

exception to the otherwise ‘‘firm is 

firm’’ policy that requires all firm users 

to be curtailed pro-rata. 

Commission Determination 

1091. The Commission will allow 

conditional firm point-to-point service 

to qualify as firm service that supports 

the designation of network resources 

imported from other control areas. As 

we explain in more detail in section 

V.D.6, the Commission has longstanding 

limitations on network resources. 

Network resources cannot be 

interrupted for economic reasons and 

third-party transmission arrangements 

to deliver the resource to the network 

must be non-interruptible.669 EEI is 

incorrect that, under our precedent, a 

resource must be ‘‘noncurtailable’’ to 

qualify as a network resource under the 

OATT. All resources are ‘‘curtailable’’—

e.g., if a unit trips off line, the resource 

is, by definition, curtailed. Network 

resources may also be unavailable due 

to other reasons besides an unplanned 

unit outage, such as unplanned 

transmission outages or environmental 

restrictions. It is appropriate to allow 

conditional firm service to support the 


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12406 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

670See section V.C.1 of this Final Rule for a 

discussion of comments regarding independent 

dispatch and spot market development. 

671Transparent Dispatch Advocates’ proposal for 

mandatory coordination agreements between 

transmission providers for provision of redispatch 

service is addressed in section V.C.1 of this Final 

Rule. 

designation of network resources 

because the conditional firm option 

only affects the transmission of the 

resource to the network, not the 

interruptibility of the generating 

resource itself. Conditional firm service 

satisfies the Commission’s requirement 

for the delivery of the resource to the 

network to be non-interruptible because 

such transmission service is curtailable 

only for specific reliability reasons, not 

economic reasons. 

1092. We decline, however, to adopt 

the conditional firm option for network 

service. Commenters argue that 

conditional firm network service should 

be made available to prevent 

conditional firm point-to-point service 

from ‘‘trumping’’ the scheduling of 

secondary network service and to 

ensure that network service is at a 

minimum equivalent to point-to-point 

service. Concerns regarding conditional 

firm point-to-point service ‘‘trumping’’

secondary network service would not be 

resolved by creating conditional firm 

network service. The ‘‘as available’’

nature of secondary network service 

will still permit all firm uses of the 

system, including conditional firm 

service, to have a higher reservation 

priority than secondary network service. 

Creating a conditional firm network 

service would not change that 

reservation priority. 

1093. Others argue that conditional 

firm network service should be required 

in order to ensure that network service 

is equivalent to point-to-point service. 

As noted above, however, the two 

services are not precisely the same, nor 

were they intended to be identical. In 

Order No. 888, the Commission 

attempted to strike a balance between 

competing interests in designing 

network and point-to-point transmission 

services, each service with its own costs 

and benefits. It is therefore appropriate 

that we consider the need for 

conditional firm service in each context. 

While we conclude that implementation 

of conditional firm network service is 

not necessary to remedy undue 

discrimination at this time, we note that 

allowing conditional firm point-to-point 

service will nonetheless provide 

substantial benefits to network 

customers by allowing the designation 

of network resources delivered to the 

network from other control areas using 

conditional firm point-to-point service. 

Conditional firm point-to-point service 

will thereby allow network customers to 

access new alternative power sources. 

Transmission providers are free to make 

a filing under FPA section 205 

proposing conditional firm network 

service. 

1094. Finally, in light of our 

conclusions above that conditional firm 

service satisfies the Commission’s 

requirements for designating network 

resources because the delivery of the 

resource to the network is not 

interruptible for economic reasons, we 

do not need to adopt a seasonal, 

monthly or periodic method for 

determining the conditions under which 

conditional service may be curtailed as 

suggested by EEI and others. 

b. Proposals for Transparent Redispatch 

NOPR Proposal 

1095. In the NOPR, the Commission 

explained that the major focus of this 

rulemaking was to strengthen the pro 

forma OATT in order to remedy undue 

discrimination rather than create new 

market structures. The Commission 

stated its intention to retain the use of 

an OATT to facilitate the development 

of competitive wholesale markets by 

reducing barriers to entry through the 

control of transmission assets, not 

impose any particular market structure 

on the industry. 

Comments 

1096. Several commenters argue that 

the Commission should expand the 

planning redispatch requirements of the 

pro forma OATT to incorporate third 

party provision of redispatch and 

bidding protocols.670 In reply 

comments, Transparent Dispatch 

Advocates submitted a proposal that, 

among other things, would require 

transmission providers to (1) post the 

real-time cost estimate of providing 

redispatch service from their resources 

at congested locations, (2) accept offers 

from third parties to provide redispatch 

service, and (3) provide real-time 

redispatch to resolve transmission 

constraints. Transparent Dispatch 

Advocates argue that their proposal is 

consistent with the scope of the 

rulemaking because it would not require 

the adoption of LMP markets or other 

standardization; rather, it would simply 

provide cost visibility and proper cost 

assignment of the dispatch decisions 

made by transmission providers. 

1097. In a notice issued on November 

15, 2006, the Commission sought further 

comment on the TDA proposal. The 

Commission asked, inter alia, about 

implementation impediments and 

confidentiality issues related to posting 

redispatch costs, whether the TDA 

proposal was required to remedy undue 

discrimination, and whether third party 

participation in redispatch would 

require market mechanisms. 

Commission Determination 

1098. The Commission addresses 

below two distinct parts of the TDA 

proposal: (1) Expansion of transmission 

provider’s real-time reliability 

redispatch obligation as well as 

inclusion of third-party resources in 

provision of redispatch and (2) posting 

of real-time redispatch costs or 

prices.671 The Commission has carefully 

considered both the TDA proposal and 

the comments respecting it. We agree 

with many of the public policy goals 

articulated by Transparent Dispatch 

Advocates, such as increasing the 

transparency of information and 

increasing the efficient use of existing 

infrastructure. However, we also agree 

with many of the commenters that 

certain aspects of the TDA proposal are 

unclear and, depending on its 

interpretation, may require the creation 

of new services under the pro forma 

OATT or new market structures. We are 

particularly cognizant of the arguments 

of customer groups such as APPA, 

NRECA and TAPS that the TDA 

proposal may be difficult to implement, 

contentious, and may not provide 

significant benefits to customers. These 

customers also are concerned that it 

may detract from other reforms 

considered in this proceeding that they 

believe provide greater benefits, such as 

transmission planning reform. 

1099. After considering the views of 

all the parties, the Commission has 

sought to strike a reasonable balance 

between the positions of the 

commenters. On the one hand, we adopt 

certain reforms that will provide 

additional information regarding 

redispatch costs in a manner that 

benefits consumers. On the other hand, 

we will not adopt the portions of the 

TDA proposal that would require the 

creation of new services under the pro 

forma OATT or new market structures. 

We do not believe that such 

fundamental changes are necessary or 

appropriate at this time, nor do we have 

an adequate record upon which to adopt 

them. 

1100. Specifically, the Commission 

declines to adopt the TDA proposal to 

expand transmission providers’ realtime reliability redispatch obligations 

and incorporate third party bids into 

redispatch. As discussed in detail 

above, transmission providers will 

continue to have an obligation to 


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672Transparent Dispatch Advocates Reply at 5. 

673E.g., EPSA and AWEA Supplemental, 

Constellation Supplemental, California Commission 

Supplemental, PPL Supplemental, BP Energy 

Supplemental, PPM, and San Diego G&E. 

perform reliability redispatch for 

network customers and provide the 

planning redispatch described above for 

point-to-point customers. Transmission 

providers will not be required, as 

Transparent Dispatch Advocates 

request, to incorporate third party 

resources when providing reliability 

redispatch or evaluating planning 

redispatch options for point-to-point or 

network transmission service. We will, 

however, institute a posting requirement 

so that the actual costs of redispatch 

under existing and future redispatch 

agreements is made transparent to 

potential customers. While we will not 

require posting of a real-time estimate of 

redispatch prices as proposed by 

Transparent Dispatch Advocates, the 

Commission concludes that the posting 

requirement required herein will 

provide important information 

regarding the costs of redispatch 

without revealing confidential 

information that might harm existing 

markets. 

(1) Expansion of Reliability Redispatch 

Obligation and Inclusion of Third Party 

Resources 

Comments 

1101. In reply comments filed 

September 20, 2006, Transparent 

Dispatch Advocates argue that the 

Commission must bring transparency to 

the dispatch function to make 

redispatch effective and fair and to 

thereby remedy the potential for 

discriminatory provision of 

transmission service. Transparent 

Dispatch Advocates assert that the 

Commission should require each 

transmission provider to publish a 

‘‘dynamic real-time value of what it 

would charge to provide redispatch 

service at specified congestion locations 

within the transmission provider’s 

system and at specified flowgates at the 

border of the transmission provider’s 

system.’’ 672 Transparent Dispatch 

Advocates contend that the publication 

of this data would: Allow customers to 

assess available real-time redispatch 

options; allow customers to access 

redispatch at actual costs; allow 

customers to predict with reasonable 

certainty the costs of redispatch; allow 

all resource owners to voluntarily offer 

redispatch solutions and be properly 

compensated for their efforts; and over 

time, support long-term transmission 

service. 

1102. In reply comments, Transparent 

Dispatch Advocates further request 

adoption of rules that would either 

require the transmission provider to 

account for independent, third party 

resources in its control area in 

establishing redispatch costs, or allow 

independent resources to post real-time, 

cost-based price and quantity bids for 

redispatch plus the resource’s impact on 

the constraint on the transmission 

provider’s OASIS. Transparent Dispatch 

Advocates state that the published 

redispatch values would be cost-based 

in non-market environments. 

1103. On November 3, 2006, a 

summary of, and frequently asked 

questions regarding, the TDA proposal 

(TDA Summary) was attached to 

comments filed by San Diego G&E in 

response to the October 12 Technical 

Conference and in support of the TDA 

proposal. In the TDA Summary, 

Transparent Dispatch Advocates assert 

that the Commission need only revise 

the existing redispatch provisions of the 

pro forma OATT to require posting by 

the transmission providers of the nature 

of congestion at pre-designated 

flowgates and data concerning the 

response required to relieve congestion. 

Additionally, the TDA Summary states 

that the transmission provider would 

have no obligation to provide for realtime redispatch from its own or 

affiliated generation; rather, all 

generators wishing to provide 

redispatch could volunteer to submit 

bids. Transparent Dispatch Advocates 

state that these bids could be either 

market or cost based depending on 

whether the bidder has market-based 

rates within the control area. The 

transmission provider would be 

obligated to evaluate the bids, publish 

the price for redispatch, and call on 

generators to provide the requested 

redispatch in real time. Transparent 

Dispatch Advocates suggest that 

transmission providers calculate the 

price for redispatch by taking the 

difference between bids received by 

those generators that the transmission 

provider would call upon to increase 

output (i.e., to redispatch) and the costs 

the transmission provider otherwise 

would have paid the generator whose 

output is lowered to relieve the 

constraint. Transparent Dispatch 

Advocates contend that their proposal 

differs from LMP markets because, 

while LMP sets system-wide clearing 

prices, their transparent redispatch 

proposal would apply only at selected 

flowgates and only with respect to those 

transacting at those flowgates. 

1104. On December 15, 2006, in 

supplemental comments filed in 

response to the Commission’s November 

15 Notice asking for comment on the 

TDA proposal, Transparent Dispatch 

Advocates sought to clarify their 

proposal. Transparent Dispatch 

Advocates propose that the Commission 

impose upon transmission providers an 

obligation to do the following: Provide 

reliability redispatch to point-to-point 

customers in real-time for comparable 

treatment to that currently provided to 

network customers and native load; 

consider their own resources, network 

resources, and offers from non-network 

resources in providing least cost 

redispatch in real-time; and, publish 

real-time information about the cost of 

redispatch (including the prices 

submitted by non-network resources) on 

its OASIS site on a frequent and timely 

basis. In their supplemental comments, 

Transparent Dispatch Advocates 

propose a different method for 

calculating redispatch prices using the 

difference between the cost of the 

generation raised and the pre-redispatch 

transmission provider’s system-wide 

marginal cost (e.g., system lambda). 

Transparent Dispatch Advocates further 

propose that point-to-point redispatch 

customers taking this service would not 

be subject to curtailment along with 

other firm customers in accordance with 

the current OATT curtailment rules. 

Transparent Dispatch Advocates argue 

that their modified proposal would 

facilitate comparable access to 

redispatch service and ensure that the 

existing redispatch provisions of the 

OATT can be made effective. 

1105. Several parties offer comments 

in support of the TDA redispatch 

proposal.673 Constellation encourages 

the Commission to fully consider the 

TDA proposal in the appropriate 

context, whether in this docket or in a 

separate proceeding. California 

Commission states that a movement of 

OATT policy in the direction implied 

by the TDA proposal is necessary to 

improve efficiency of generation and 

transmission investment. BP Energy 

believes that a redispatch mechanism is 

necessary to minimize aggregate 

consumer costs and make redispatch 

equally available to all participants. 

PPM supports the TDA proposal noting 

that it would provide sufficient cost 

certainty for both the transmission 

provider and the customer and make 

more efficient use of the existing grid 

without impacting reliability. Although 

it opposed the proposal initially, MISO 

states that it now cautiously supports 

the TDA redispatch proposal, provided 

that RTOs do not bear an inappropriate 

share of costs to modify information 

technology systems. 


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12408 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

674E.g., LPPC Supplemental, Community Power 

Alliance Supplemental, Public Power Council 

Supplemental, Pacific Coast Parties Supplemental, 

EEI Supplemental, Duke Supplemental, Southern 

Supplemental, Southwest Utilities Supplemental, 

South Carolina E&G Supplemental, Ameren 

Supplemental, Alabama Commission 

Supplemental, Florida Commission Supplemental, 

Georgia Commission Supplemental, North Carolina 

Commission Supplemental, South Carolina 

Regulatory Staff, and SEARUC Supplemental. 

675E.g., Alabama Commission Supplemental, 

Florida Commission Supplemental, Georgia 

Commission Supplemental, North Carolina 

Commission Supplemental, South Carolina 

Regulatory Staff, and SEARUC Supplemental. 

676Commenters reference a proposal in a 

proceeding terminated by the Commission. See 

Remedying Undue Discrimination through Open 

Access Transmission Service and Standard 

Electricity Market Design, 67 FR 55454 (Aug. 29, 

2002), FERC Stats. & Regs. ¶ 32,563 (2003), 

terminated by, 112 FERC ¶ 61, 073 (2005). 

677E.g., Community Power Alliance 

Supplemental, and Entergy Supplemental. 

678EPSA and AWEA Supplemental, BP Energy 

Supplemental, California Commission 

Supplemental. 

679E.g., LPPC Supplemental, Community Power 

Alliance Supplemental, Public Power Council 

Supplemental, Pacific Coast Parties Supplemental, 

EEI Supplemental, Duke Supplemental, South 

Carolina E&G Supplemental, Ameren 

Supplemental, North Carolina Commission 

Supplemental, South Carolina Regulatory Staff 

Supplemental, and North Carolina Commission 

Supplemental. 

1106. Many commenters oppose the 

TDA proposal stating that the record in 

this proceeding does not warrant 

implementing such a complex and 

uncertain proposal which imposes 

significant risks, costs and burdens on 

transmission providers and their native 

load customers.674 Public Power 

Council, Southern, and NRECA do not 

believe that the Commission should 

adopt the TDA proposal without an 

analysis of costs and benefits and note 

that no party has provided any such 

analysis. OG&E and Public Power 

Council state that the costs of 

congestion likely vary greatly by region 

and argue that Transparent Dispatch 

Advocates have provided no evidence 

that their industry-wide solution solves 

potential regional redispatch problems. 

1107. Several state commissions 

oppose adoption of the TDA proposal or 

urge the Commission to impose 

significant conditions on the proposal to 

protect retail customers.675 SEARUC, 

Alabama Commission, Florida 

Commission, Georgia Commission, 

North Carolina Commission and South 

Carolina Regulatory Staff express 

concern that the TDA proposal would 

make competitively sensitive 

information available to the public on 

an inconsistent basis, compel the 

provision of additional services that risk 

increasing retail costs, harm reliable 

service to retail ratepayers that state 

commissions are obligated by state laws 

to protect, impose administrative 

difficulties and excessive 

implementation costs, and compel states 

or regions to change current practices or 

market structures in contradiction of 

EPAct 2005. SEARUC asks the 

Commission to make clear that 

implementation of a proposal targeted at 

enhancing transparency will not result 

in a federally imposed change in 

economic dispatch practices or lessen 

the amount of firm capacity available for 

service to native load customers. 

SEARUC also expresses concern 

regarding the imposition of incremental 

costs upon retail ratepayers without 

prior state approval or the 

implementation of any type of process 

or organization that has not been 

approved by state regulators as cost 

effective for retail customers. SEARUC 

opposes the mandatory use of LMP or 

LMP-like pricing, congestion 

management approach or organized 

wholesale market structure without 

prior state endorsement; and the 

mandatory posting of competitively 

sensitive, generation plant-specific costs 

or price information. 

1108. Georgia Commission states that 

radical restructuring is not necessary to 

achieve the goals stated by the 

Commission in the NOPR. Alabama 

Commission, Georgia Commission and 

South Carolina Regulatory Staff state 

that analyses associated with potential 

implementation of new market 

structures in the Southeast have 

demonstrated that the implementation 

costs associated with such structures 

vastly outweigh the benefits. North 

Carolina Commission argues that the 

TDA proposal fails to comply with the 

Commission’s directive in the NOI. In 

its view, the Commission intended to 

focus in this proceeding on specific 

problems that continue to exist and 

targeted remedies. 

1109. North Carolina Commission 

states that the Transparent Dispatch 

Advocates’ reply comments incorrectly 

equate the use of redispatch for 

economic purposes pursuant to 13.5 of 

the pro forma OATT with its use for 

reliability purposes. North Carolina 

Commission maintains that these 

services are not comparable, and thus 

the use of redispatch for reliability 

purposes does not justify requiring a 

transmission provider to provide it for 

economic purposes. North Carolina 

Commission asserts that 

implementation of the TDA proposal 

would result in substantial benefits 

accruing to PJM without commensurate 

benefits to non-RTO areas. North 

Carolina Commission, Southwest 

Utilities and Southern argue that the 

costs of implementing the proposal are 

not justified by any potential efficiency 

benefits and thus there is a compelling 

reason to reject the TDA proposal. 

1110. Several parties argue that the 

TDA proposal represents a move toward 

Standard Market Design (SMD).676

Alabama Commission, Georgia 

Commission and North Carolina 

Commission submit that the TDA 

proposal shares characteristics with the 

centralized dispatch and LMP proposals 

advanced in the SMD proceeding and 

thus conflict with state commission 

jurisdiction in much the same manner 

as the SMD proposal. Georgia 

Commission and others assert that the 

only difference between the SMD 

proposal and TDA proposal is that the 

TDA proposal would require 

transmission providers, but not third 

party merchants, to make their costs 

transparent.677 NRECA believes that a 

real-time pricing scheme based on some 

value other than actual costs constitutes 

the creation of a new product and an 

organized, bid-based market in regions 

that have not adopted such market 

structures. NRECA contends that it 

would be politically unacceptable to 

reform the OATT in a manner that 

necessitates the formation of regional 

bid-based markets in non-RTO areas. 

1111. In contrast, California 

Commission supports the TDA proposal 

to the effect that transmission providers 

should be required to post redispatch 

cost information and to provide realtime redispatch. In supplemental 

comments, California Commission 

asserts that this effort is needed to 

prevent undue discrimination, for 

improved efficiency of generation and 

transmission investment and to improve 

the efficiency, transparency and 

openness of redispatch, and 

transmission access generally. 

1112. Some commenters argue that 

the TDA proposal is necessary to 

remedy undue discrimination.678 Others 

disagree.679 Transparent Dispatch 

Advocates contend that making realtime economic dispatch available to 

‘‘non-network transmission customers’’

is necessary to remedy undue 

discrimination against those customers 

as compared with network customers. In 

their supplemental comments, EPSA 

and AWEA state that the TDA proposal 

is necessary to remedy the same undue 

discrimination targeted by the NOPR 

proposal pertaining to planning 

redispatch service. PPL suggests that the 

TDA proposal may permit transmission 

customers to benefit from redispatch, 

which transmission owners in non-RTO 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12409 

680E.g., LPPC Supplemental, Community Power 

Alliance Supplemental, Public Power Council 

Supplemental, Pacific Coast Parties Supplemental, 

EEI Supplemental, Duke Supplemental, 

MidAmerican and Progress Energy Supplemental, 

South Carolina E&G Supplemental, Ameren 

Supplemental, North Carolina Commission 

Supplemental, North Carolina Commission Staff 

Supplemental, and North Carolina Commission 

Supplemental. 

681E.g., Entergy Supplemental, LPPC 

Supplemental, Public Power Council Supplemental, 

and OG&E Supplemental. 

682E.g., Pacific Coast Parties Supplemental, 

Southwest Utilities Supplemental, Entergy 

Supplemental, EEI Supplemental, PPL 

Supplemental, Public Power Council Supplemental, 

Florida Commission Supplemental, SEARUC 

Supplemental, Progress Energy and MidAmerican 

Supplemental, APPA Supplemental, NRECA 

Supplemental, and TAPS Supplemental. 683E.g., Progress Energy and MidAmerican 

Supplemental, APPA Supplemental, NRECA 

Supplemental, and TAPS Supplemental. 

areas now employ to benefit themselves 

or their native load customers. 

1113. A number of commenters assert 

that neither the record nor Transparent 

Dispatch Advocates present evidence of 

discriminatory treatment of 

transmission customers with regard to 

transparent redispatch.680 South 

Carolina E&G asserts that 

implementation of the TDA proposal 

should not be unjustifiably forced onto 

individual transmission providers given 

that there is no demonstration that there 

is a problem. MidAmerican and 

Progress Energy and others argue that 

unsupported assertions of undue 

discrimination are insufficient to 

support the TDA proposal. These 

commenters argue that pursuant to the 

recent National Fuel decision, the 

courts would likely require the 

Commission to overcome substantial 

hurdles in order to adopt the TDA 

proposal based on theoretical assertions 

of undue discrimination.681 These 

commenters contend that the National 

Fuel case would likely require the 

Commission to demonstrate how 

potential undue discrimination justifies 

a costly redispatch proposal, why 

section 206 rights are insufficient to 

ensure redispatch is comparably 

provided, and why the comparability 

findings of Order No. 888 are no longer 

sufficient. 

1114. In response to assertions that 

utilities routinely redispatch to meet 

electric load, LPPC argues that there is 

nothing discriminatory about a 

vertically integrated utility’s use of its 

own nonjurisdictional generation to 

support bundled sales service. LPPC 

states that the use of generation first to 

serve native load has been the 

fundamental operating principal for 

jurisdictional and nonjurisdictional 

utilities for decades, and certainly under 

Order No. 888. LPPC concludes that this 

is not a problem calling for Commission 

attention. In response to assertions that 

TLRs are discriminatory, Duke notes 

that neither the Transparent Dispatch 

Advocates nor any other commenter has 

provided an analysis of the scope, 

location and magnitude of the TLR 

problem. 

1115. Many commenters contend that 

the TDA proposal is ambiguous, 

insufficiently developed or marked by 

inconsistencies.682 Pacific Coast Parties 

argue that the TDA proposal is too 

sweeping and contains too many 

uncertainties to allow for meaningful 

comment. Southwest Utilities believe 

that it would be premature for the 

Commission to adopt the TDA proposal 

without further development, comment, 

discussion and input from affected 

electric industry stakeholders. PPL and 

Xcel believes that the Commission 

needs to better define the proposed new 

service and allow comment on the 

service before detailed tariff language is 

developed to implement this proposed 

new service. Public Power Council 

contends that, although the proposal 

appears to seek only the posting of 

information, in reality, Transparent 

Dispatch Advocates ask that the 

Commission require reciprocal 

redispatch coordination. Public Power 

Council also argues that the TDA 

proposal is silent or ambiguous 

concerning critical issues associated 

with implementation; the proposal fails 

to explain the ‘‘cost’’ at which 

transmission providers would offer 

redispatch or the price, terms, and 

conditions of such a transaction. 

1116. Several parties refer to seeming 

discrepancies between Transparent 

Dispatch Advocates’ explanations of the 

proposal and question whether the TDA 

proposal entails cost-based or marketbased bidding.683 APPA notes that 

Transparent Dispatch Advocates state in 

reply comments that effective 

redispatch service must reflect actual 

costs. APPA adds that the TDA 

Summary, in contrast, provides that any 

generator with market-based rate 

authority in the transmission provider’s 

control area could charge a marketbased price for generation offered for 

redispatch service. LPPC, TDU Systems, 

TAPS, APPA and NRECA express 

concern about allowing redispatch 

providers to bid under market-based 

rate authority. These commenters argue 

that reliance on existing market-based 

rate authority to support redispatch 

offers no protection against the exercise 

of market power, given the high 

concentration of transmission providerowned generation within its control 

area. If the Commission adopts the TDA 

proposal, APPA asserts that the 

Commission should limit all sellers of 

generation used for redispatch service to 

cost-based bids and require all parties to 

provide cost information. 

1117. In supplemental comments, EEI 

and Public Power Council assert that the 

Commission in seeking comment on the 

TDA proposal has not proposed a rule 

with sufficient clarity to allow 

meaningful comment and, therefore, it 

would be inappropriate to adopt the 

TDA proposal based on this 

proceeding’s record. Pacific Coast 

Parties add that the Commission cannot 

adopt the TDA proposal based on the 

sparse record in this proceeding. 

MidAmerican and Progress Energy 

contend that the Commission’s notice 

here does not satisfy Administrative 

Procedure Act requirements for public 

notice and comments on the TDA 

proposal. In their view, the Commission 

must initiate a separate rulemaking 

proceeding to evaluate the TDA 

proposal. 

1118. Progress Energy and 

MidAmerican assert that, under the 

current pro forma OATT, redispatch is 

based on a ‘‘careful’’ evaluation of the 

reliability and cost impacts of using 

redispatch on a long-term basis and thus 

the transmission provider is able to 

serve transmission customers and 

wholesale load-serving obligations at 

least cost. In their view, the 

transmission provider’s retail and 

wholesale customers would absorb the 

costs to serve transmission customers 

that obtain the forced real-time 

redispatch under the TDA proposal. 

1119. Community Power Alliance, 

North Carolina Commission, Progress 

Energy and MidAmerican contend that 

native load customers would be harmed 

by a requirement that transmission 

providers sell their excess generation to 

redispatch customers. They state that 

such a requirement would prevent or 

reduce the sale of generation in 

competitive markets and that these 

market sales would otherwise reduce 

costs to native load customers. 

Moreover, where the transmission 

provider is required to redispatch its 

own generation, Progress Energy and 

MidAmerican argue that Transparent 

Dispatch Advocates’ proposed 

redispatch would either use more 

expensive units or cause the 

transmission providers to lose the 

opportunity to make higher valued 

sales, which also increases costs for 

native load customers. 

1120. In supplemental comments, 

E.ON, Progress Energy and 

MidAmerican assert that some 

generators face limits with regard to the 


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12410 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

684E.g., LPPC Supplemental, TAPS 

Supplemental, NRECA Supplemental, Southern 

Supplemental, South Carolina E&G Supplemental, 

and E.ON Supplemental. 

685E.g., Nevada Companies Supplemental, 

Community Power Alliance Supplemental, 

Southwest Utilities Supplemental, and Southern 

Supplemental. 

686E.g., APPA Supplemental, LPPC 

Supplemental, TDU Systems Supplemental, NRECA 

Supplemental, Progress Energy and MidAmerican 

Supplemental, Southern Supplemental, Duke 

Supplemental, OG&E Supplemental, Georgia 

Commission Supplemental, and North Carolina 

Commission Supplemental. 

687E.g., Community Power Alliance 

Supplemental, Southwest Utilities Supplemental, 

Florida Commission Supplemental, Ameren 

Supplemental, and Entergy Supplemental. 

amount of time that they are allowed to 

operate due to air emissions caps and 

maintenance schedules. They contend 

that the TDA proposal could cause 

allowable run time to be ‘‘used up’’

prior to the time that the generator has 

fulfilled its planned native load 

obligation, thus requiring that the 

transmission provider resort to 

alternative, likely more expensive, 

power supplies for these obligations. 

1121. Several parties assert that 

Transparent Dispatch Advocates’

proposal to substitute redispatch for 

transmission upgrades will depress 

transmission investment.684 LPPC 

argues that Transparent Dispatch 

Advocates’ proposal conflicts with the 

Commission’s policy of promoting 

transmission infrastructure 

development. NRECA states that, to the 

extent that redispatch is required to 

fulfill long-term point-to-point service 

on a particular transmission provider’s 

system, such providers have failed to 

meet their obligations under the existing 

OATT to plan and expand the system 

for those transmission customers’ longterm needs. NRECA envisions 

redispatch customers potentially 

requesting ‘‘ever more convoluted’’

dispatch rules in order to avoid 

transmission upgrades. NRECA prefers 

better enforcement of section 15.4 of the 

OATT in conjunction with a more open 

and inclusive planning process. TAPS 

argues that transmission providers will 

profit from market-based prices for 

redispatch and will be discouraged from 

transmission expansion. TAPS contends 

that PJM has conceded that LMP signals 

have proven insufficient to create a 

robust grid. In TAPS view, this counters 

Transparent Dispatch Advocates’ claims 

that their proposal will reveal the value 

of transmission upgrades and encourage 

investment. 

1122. Several commenters submit that 

the TDA proposal raises Standards of 

Conduct issues.685 They argue that 

requiring the TDA proposal would 

complicate if not undermine the 

functional separation and information 

sharing policies of the Standards of 

Conduct because the transmission 

function would be performing 

merchant, or at least merchant-related, 

functions. According to Community 

Power Alliance, the requirement that 

transmission providers allow merchant 

generators to offer to sell generation to 

alleviate constraints in order that other 

customers’ transactions could flow 

would violate Standards of Conduct. 

1123. TAPS argues that accurately 

forecasting the price of long-term firm 

service may be difficult and thus the 

TDA proposal would not provide 

adequate levels of certainty to facilitate 

long-term service. 

1124. Mark Lively asserts that the 

TDA proposal fails to address other 

types of redispatch, including loop flow, 

reactive power, Inadvertent Interchange 

and intra-hour interchange, and as such 

will result in suboptimal operation of 

the network. 

1125. OG&E questions whether the 

TDA proposal would apply to RTOs but 

if so, OG&E argues that the proposal 

should be rejected. OG&E contends that 

the Commission explained in Order No. 

2000 that congestion management is a 

regional function and that the TDA 

proposal should not apply to a 

transmission provider located within an 

RTO. 

1126. In supplemental comments, 

Transparent Dispatch Advocates 

contend that the transparent dispatch 

proposal would not involve the 

establishment of organized markets of 

any sort; rather, it simply would require 

the posting of redispatch costs. 

Transparent Dispatch Advocates state 

that the proposal only requires the 

consideration by the transmission 

provider of additional price data from 

non-network resources and minimal 

adjustments in transmission provider’s 

reporting systems. 

1127. Several parties disagree with 

Transparent Dispatch Advocates and 

argue that the proposal would require 

the establishment and operation of 

markets by transmission providers.686

APPA and TDU Systems assert that 

under the TDA proposal transmission 

providers would select bids, from 

among a variety of affiliated and 

unaffiliated resources, that most 

effectively relieve constraints. 

Community Power Alliance, Georgia 

Commission, Southern and Entergy 

assert that the TDA proposal would 

result in the establishment of formal 

LMP markets in non-RTO/ISO areas, or 

at least start down the ‘‘slippery slope’’

to LMP markets. Community Power 

Alliance and Entergy contend that 

adoption of the TDA proposal is in 

conflict with the purpose of the 

rulemaking as stated in the NOPR and 

Congress’ focus on protecting native 

load and ensuring reliability in EPAct 

2005. 

1128. APPA argues that the 

implementation of the TDA proposal 

would require the following: 

designation and posting by the 

transmission provider of chosen 

flowgates; posting by the transmission 

provider of the desired characteristics of 

generation or demand-side responses 

that could alleviate such constraints; 

posting by the transmission provider of 

historical redispatch costs; resolution of 

whether public utility transmission 

providers can be required to provide 

generation resources for redispatch; 

resolution of whether transmission 

providers would be discriminated 

against if they were not permitted to 

charge market-based rates; 

administration by the transmission 

provider of short-term (daily or hourly) 

market for redispatch, notwithstanding 

a conflict of interest between the 

transmission provider’s market-making 

and market-participant roles and 

possibly third-party monitoring of 

market administration. 

1129. APPA, Xcel, North Carolina 

Commission, and NRECA raise concerns 

over the costs of establishing and 

administering redispatch markets and 

systems, including the costs of 

hardware, software, communication 

systems, billing and reporting systems. 

North Carolina Commission submits 

that the costs of implementing the TDA 

proposal would be substantial because 

there are no current practices or rules on 

which to model structures for the TDA 

proposal. Other commenters similarly 

assert that the TDA proposal would 

impose significant administrative 

burdens and expenses on transmission 

providers, especially if an independent 

entity were required for 

implementation, and that most of these 

costs would be shifted to native load 

customers.687 Xcel argues that 

redispatch cannot be cost-effectively 

managed unless done within the context 

of a regional Day 2 energy market. 

1130. NRECA asserts that 

transmission providers would need an 

enormous amount of data, including 

resource status, marginal generation 

costs, start up costs, ramp rates, and 

environmental costs of operation, to 

redispatch resources. NRECA asserts 

that the allocation of redispatch costs 

for multiple customers taking redispatch 

may be difficult. 


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688E.g., APPA Supplemental, LPPC 

Supplemental, Community Power Alliance 

Supplemental, South Carolina E&G Supplemental, 

Progress Energy and MidAmerican Supplemental, 

and Southern Supplemental. 

689Transparent Dispatch Advocates Reply at 17. 

690Citing Northwest Pipeline Corp. v. FERC, 905 

F.2d 1403, 1410–11 (10th Cir. 1990); Detroit Edison 

Co. v. FERC, 334 F.3d 48, 54–55 (D.C. Cir. 2003). 

691 372 F.3d 395 (D.C. Cir. 2004). 

692Compare Transparent Dispatch Advocates 

Supplemental at 2 n.4 (stating that the proposed 

service would supplement the existing OATT 

requirement to provide redispatch to long-term firm 

point-to-point customers) and Transparent Dispatch 

Advocates Supplemental at 5 (discussing the 

proposal as a remedy for undue discrimination 

against firm point-to-point customers) with 

Transparent Dispatch Advocates Supplemental at 

14–15 (demonstrating the redispatch pricing 

mechanism for a non-firm transaction). 

693Transparent Dispatch Advocates Reply at 18. 

1131. Xcel, APPA, and TDU Systems 

assert that the TDA proposal would not 

address concerns about subjective 

redispatch decisions by transmission 

providers. TDU Systems argue that the 

proposal would allow for the functional 

equivalent of an RTO market, without a 

market administrator that satisfies the 

independence criteria of Order No. 2000 

or Order No. 888. APPA asserts that 

posting of information concerning the 

nature of congestion at designated 

flowgates would be followed by 

differences of opinion as to how the 

dispatch entity is exercising its 

judgment in calculating the costs and in 

redispatching resources. 

1132. Southwest Utilities and 

Southern assert that the proposal raises 

significant questions regarding 

commercial, operational, economic, and 

compliance issues that remain 

unanswered. For example, Southwest 

Utilities argues that it would appear that 

under the TDA proposal a transmission 

provider accepting a third party bid 

would be required to assume the 

commercial obligation, including credit 

risk associated with the bid and the 

posting of collateral, and would execute 

the contract with the third party bidder 

under currently unspecified terms and 

conditions. Southwest Utilities and 

Southern further argue that the proposal 

fails to resolve how operational and 

economic liability to the redispatch 

customer would be impacted in the 

event of non-performance by a third 

party supplier. Southwest Utilities also 

asserts that it is unclear whether the 

TDA proposal could function within the 

rated path/contract path model of much 

of the Western Interconnection. 

1133. Many parties argue that 

implementation of the TDA proposal 

would raise jurisdictional issues.688

Community Power Alliance, South 

Carolina E&G, Progress Energy, 

MidAmerican and Southern assert that 

the TDA proposal conflicts with state 

and federal laws in that it forces 

transmission providers to use generation 

(that was built, dedicated and 

dispatched to serve retail and wholesale 

customers at least cost) to serve other 

wholesale suppliers and customers. 

Community Power Alliance argues that 

states, not the Commission, have 

authority to regulate how utilities 

dispatch generation and procure 

resources. Further, Community Power 

Alliance asserts that requiring utilities 

to establish platforms for third-party 

generators’ offers would convert the 

transmission function into a generation 

procurement function, violating the 

scope of the Commission’s jurisdiction. 

Southern, LPPC and North Carolina 

Commission add that the TDA proposal 

would be in violation of section 201 of 

the FPA that expressly limits the 

Commission’s jurisdiction to matters 

which are not subject to regulation by 

the States. Southern further asserts that 

this is made clearer by the exclusion in 

section 201 of ‘‘facilities used for the 

generation of electric energy’’ from the 

Commission’s jurisdiction. Southern 

contends that mandated cost-based sales 

would also constitute an unlawful 

taking of private property under the 

Fifth Amendment of the Constitution. 

1134. LPPC states that Transparent 

Dispatch Advocates seek to reason 

around section 201 of the FPA in 

arguing that redispatch ‘‘does not 

involve the sale of electricity for re-sale 

or consumption; it involves the 

provision of a service to support 

transmission service.’’ 689 LPPC 

counters that, in redispatch, generation 

is used instead of transmission service 

rather than in support of transmission 

service. North Carolina Commission, 

LPPC and APPA argue that the courts 

have previously rejected Commission 

attempts to extend regulation to matters 

specifically excluded, statutorily, from 

regulation on the grounds that they are 

the functional equivalent of a 

jurisdictional service.690 LPPC also 

asserts that section 217 of the FPA 

specifies that utilities have a right to use 

their transmission facilities on a priority 

basis in order to meet their core service 

obligations. 

1135. North Carolina Commission 

asserts that in Order No. 888 the 

Commission interpreted its authority 

under sections 205 and 206 of the FPA 

to include the effect the Rule may have 

over generation facilities because 

preventing undue discrimination is one 

of the matters specifically provided for 

in Part II. North Carolina Commission 

argues that California Independent 

System Operator v. FERC,691 however, 

establishes limits on how broadly 

sections 205 and 206 can be interpreted. 

North Carolina Commission contends 

that sections 205 and 206 historically 

have been interpreted to apply to the 

rates for wholesale sales and purchases, 

rather than to the underlying generating 

facilities. As a result, North Carolina 

Commission argues that the adoption of 

the TDA proposal could not be justified 

under these provisions of the FPA. 

Commission Determination 

1136. The Commission agrees with 

the Transparent Dispatch Advocates 

proponents that greater transparency of 

reliability redispatch information can 

provide benefits to consumers, as well 

as increase efficient use of the existing 

transmission grid. We are therefore 

adopting certain reforms, as explained 

in the section below, that will increase 

the availability and transparency of 

redispatch costs. However, we are 

adopting these reforms in the context of 

the existing obligation to provide 

network and point-to-point transmission 

service under the pro forma OATT. We 

will not adopt the portion of TDA 

proposal that would require the creation 

of new services or any broader market 

reforms. 

1137. The TDA proposal has 

generated controversy for several 

reasons, including the lack of clarity in 

the proposal, certain inconsistencies 

that appear in Transparent Dispatch 

Advocates’ various submissions, and 

concerns that Transparent Dispatch 

Advocates’ true intent is to restructure 

bilateral markets. We believe that many 

of the concerns regarding the TDA 

proposal are overstated, but we do agree 

that it lacks clarity and consistency in 

many important respects. For example, 

it is not clear whether the proposed 

service would be available to all 

customers, any point-to-point customer 

including those taking non-firm service, 

or solely to long-term firm point-topoint customers.692 Additionally, while 

Transparent Dispatch Advocates 

contend that ‘‘the one step’’ required of 

the Commission is to implement a 

redispatch cost posting requirement,693

the TDA proposal also would require 

the Commission to expand the current 

redispatch obligations under the pro 

forma OATT and adopt complex 

settlement mechanisms to account for 

third party redispatch. The different 

TDA proposals also vary as compared 

with each other. For instance, the TDA 

Summary states that transmission 

providers would not be obligated to 

provide their resources for real-time 

redispatch, but the Transparent 


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694See pro forma OATT section 33.2; see also 

Midwest Independent Transmission System 

Operator, Inc., 84 FERC ¶ 61,231 at 62,168 (1998) 

(‘‘redispatch will be utilized to avoid the 

curtailment of firm point-to-point services, a 

requirement that is not imposed under the pro 

forma tariff.’’); Mid-Continent Area Power Pool, 87 

FERC ¶ 61,190 at 61,726–27 (1999) (finding no 

obligation to offer reliability redispatch to point-topoint customers and no obligation for point-to-point 

customers to participate in reliability redispatch). 

695See, e.g., North American Electric Reliability 

Council, 88 FERC ¶ 61,046 at 61,123–24 (1999) 

(explaining that pro rata curtailment is consistent 

with comparability even if network/native load 

reduction is accomplished by redispatch and pointto-point customer reduction is not); Northern States 

Power Co., 83 FERC ¶ 61,338 at 62,369 (1998) (the 

existence of redispatch options is not a criterion 

under the pro forma OATT for disproportionate 

curtailments), reh’g, clarification and stay denied, 

84 FERC ¶ 61,128 (1998), remanded on other 

grounds sub nom. Northern States Power Co. v. 

FERC, 176 F.3d 1090 (8th Cir. 1999) (Northern 

States Power). 

696Northern States Power, 83 FERC ¶ 61,338 at 

62,369. 

697PJM at 6. 

698Transparent Dispatch Advocates Reply at 5. 

699Transparent Dispatch Advocates 

Supplemental at 7. 

Dispatch Advocates Supplemental 

Comments make clear that the 

transmission provider would be 

obligated to use its own (or affiliated) 

resources to provide this redispatch. 

1138. We first address the contention 

of Transparent Dispatch Advocates that 

the real-time reliability redispatch 

obligation of transmission providers 

must be extended to ‘‘non-network 

transmission customers’’ to remedy 

undue discrimination. We disagree. In 

order to remedy undue discrimination, 

we have made changes to the pro forma 

OATT to implement a new conditional 

firm option for point-to-point service 

and we make changes to the existing 

planning redispatch obligation. 

However, Transparent Dispatch 

Advocates have failed to show that the 

unavailability of reliability redispatch 

for point-to-point transmission 

customers amounts to undue 

discrimination. Order No. 888 provided 

for reliability redispatch for network 

customers but not for firm point-topoint customers.694 There is a good 

reason for this distinction. The pro 

forma OATT requires network 

customers to make their generation 

resources available to the transmission 

provider to provide reliability 

redispatch to maintain the reliability of 

service to both native load and network 

customers. There is no corresponding 

obligation on point-to-point customers 

to make their generation resources 

available to provide reliability 

redispatch. Therefore, the two services 

are not comparable in this respect, 

which is why reliability redispatch 

service was not required for point-topoint customers. However, if a 

reliability problem does arise, any 

curtailment of firm point-to-point 

transmission service must be on a 

nondiscriminatory and pro rata basis 

with the treatment of network service 

and native load customers.695 The 

Commission has found that this 

treatment meets the comparability 

requirements enunciated in Order No. 

888.696

1139. Next, we also decline to adopt 

a requirement for transmission 

providers to incorporate offers to 

redispatch from third parties into their 

reliability redispatch or planning 

redispatch. Mandatory inclusion of 

third party offers is not necessary to 

remedy undue discrimination. The pro 

forma OATT obligates transmission 

providers to use their resources to 

provide, where available consistent with 

reliability, redispatch service because 

they do so when serving their native 

load customers. Third party generators 

do not have this obligation, nor do the 

Transparent Dispatch Advocates 

propose to create such an obligation. 

Rather, under the TDA proposal, 

transmission providers would remain 

obligated to provide redispatch service, 

but third party generators would have 

only the option of doing so. Transparent 

Dispatch Advocates are therefore not 

proposing comparable treatment and we 

decline to adopt the proposal. This 

notwithstanding, we believe that 

redispatch offers by third party 

generators can increase system 

reliability and reduce costs to customers 

by increasing the planning redispatch 

options available to transmission 

providers. We therefore are adopting, as 

explained above, a requirement that 

transmission providers modify their 

OASIS to allow for the posting of third 

party offers to supply planning 

redispatch. This OASIS posting 

requirement does not obligate 

transmission providers to incorporate 

bids from third parties into their 

redispatch; rather, posting of third party 

offers to provide redispatch may be used 

by transmission customers to secure 

planning redispatch provided the 

appropriate agreements are reached 

between the customer, third party 

redispatch provider, transmission 

provider and reliability coordinator. 

1140. We disagree with Transparent 

Dispatch Advocates and their 

supporters that their proposal for realtime redispatch and third party 

generation participation would allow for 

additional long-term rights through 

planning redispatch. If third party 

participation in the offer of redispatch is 

voluntary, transmission providers 

would not be able to depend upon third 

party resources in evaluating the 

availability of resources during the term 

of the planning redispatch service. 

Transmission providers therefore would 

only be able to evaluate the availability 

of their own resource as they do today. 

Thus, Transparent Dispatch Advocates 

have failed to show how its proposal 

would supplement provision of longterm rights. 

1141. Because we find that the TDA 

proposal for real-time redispatch and 

third party participation is unnecessary 

to remedy undue discrimination or 

comparability issues, we need not 

address the issue of the scope of the 

Commission’s jurisdiction as it relates to 

the TDA proposal. 

(2) Redispatch Rate Transparency 

Comments 

1142. PJM argues that if the 

Commission does not provide for 

independently administered real-time 

spot markets, it should require 

transmission providers to ‘‘make public 

their dispatch sequence and the realtime marginal costs of electricity.’’ 697 In 

reply comments, Transparent Dispatch 

Advocates request that the Commission 

require publication of ‘‘dynamic realtime value of what [each transmission 

provider] would charge to provide 

redispatch service at specified 

congestion locations within the 

transmission provider’s system and at 

specified flowgates at the border of the 

transmission provider’s system.’’ 698 In 

supplemental comments, Transparent 

Dispatch Advocates state that ‘‘[t]he 

essence of the TDA proposal is to 

require transmission providers to make 

real-time information about the cost of 

redispatch available on their OASIS in 

order to allow more efficient use of the 

transmission system.’’ 699 Transparent 

Dispatch Advocates, EPSA and AWEA 

state that the posting requirement 

should be limited to pre-determined 

flowgates and that the estimated price 

for redispatch should be posted 

frequently and sufficiently in advance of 

the hour in which the price would be 

effective in order to allow the 

transmission customer to change its 

schedule and avoid redispatch charges. 

1143. EPSA, AWEA and Transparent 

Dispatch Advocates state that since this 

information is available today and 

considered by transmission providers in 

serving their own native load, there are 

no impediments to implementing their 

proposed posting requirement. 

Transparent Dispatch Advocates argue 

that concerns about release of 

confidential data can be addressed by 


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700E.g., EPSA and AWEA Supplemental, BP 

Energy Supplemental, and California Commission 

Supplemental. 

701PGP asserts that the transmission provider 

should be required to post redispatch information 

by event and by entity to address concerns about 

anticompetitive behavior. 

702 18 U.S.C. 1905. 

703E.g., Entergy Supplemental, Community 

Power Alliance Supplemental, Progress Energy and 

MidAmerican Supplemental, Southern 

Supplemental, Southwest Utilities Supplemental, 

Nevada Companies Supplemental, OG&E 

Supplemental, Florida Commission Supplemental, 

PPL Supplemental, Ameren Supplemental, North 

Carolina Commission Supplemental, and SEARUC 

Supplemental. 

using system costs instead of unitspecific cost data to calculate the posted 

redispatch price. EPSA and AWEA state 

that there are not confidentiality issues 

with the Transparent Dispatch 

Advocates’ posting proposal because 

redispatch costs are not the costs that 

the transmission provider is incurring to 

sell energy into the market: they 

contend that redispatch costs are the net 

cost incurred by the transmission 

provider, e.g., the difference between 

the costs of ramping up and ramping 

down resources. EPSA and AWEA also 

state that there would be no competitive 

concerns over the posting of this 

information from third party suppliers 

because the suppliers names need not 

be used. 

1144. Some commenters do not 

believe that making certain information 

publicly available will result in 

confidential information disclosure.700

PPL states that while confidentiality 

concerns must be considered, the nature 

and type of information that is publicly 

provided may be structured so as to 

alleviate or minimize such concerns. 

PPL argues that rather than posting 

specific generator cost information the 

all-in price for redispatch may be posted 

instead. BP Energy argues that posting 

redispatch prices at specified locations 

reveals the economic value of adding 

transmission/generation at those 

locations, but does not reveal the 

production cost associated with specific 

generation resources. BP Energy states 

that hourly redispatch costs should be 

posted for all ‘‘significant congested 

interfaces’’ within a transmission 

provider’s control area and for all 

interfaces at control area boundaries. 

PGP asserts that transmission providers 

with OATTs should post any available 

information on hourly redispatch 

costs.701 PGP and PPL argue, however, 

that there should be an appropriate lag 

in the disclosure of actual redispatch 

costs in order to address confidentiality 

concerns. Williams states that increased 

transparency and proper monitoring are 

immediate, real solutions to ‘‘issues’’

with the posting of the cost of 

redispatch. Williams asserts that those 

customers requesting redispatch should 

be provided the cost differential 

between the original dispatch and the 

redispatch and that post audit 

redispatch data and system models can 

be made available (after the expiration 

of a non-disclosure period) to provide 

market certainty of least cost redispatch 

and appropriate bid selection. 

1145. PGP states that the redispatch 

option should be available irrespective 

of time frame, but must recognize the 

limited ability of the transmission 

provider to identify likely redispatch 

costs further out in time. Thus, PGP 

argues, posting redispatch costs in areas 

without organized markets should focus 

initially on real-time reliability 

redispatch, later expanding to longer 

time frames. PGP asserts that redispatch 

should be undertaken only when firm 

bids are available and the transmission 

customer has accepted responsibility for 

redispatch costs, which should be based 

on just and reasonable prices and must 

be known with a degree of certainty. 

PGP adds that the transmission provider 

should establish protocols that support 

firm bids, which would be published 

and, if accepted, result in binding 

obligations on the part of the bidders. 

PGP argues that it is reasonable for 

transmission providers to post real-time 

bids on constrained paths that are 

otherwise subject to curtailments to 

ensure compliance with reliability 

criteria. PGP contends that postings 

should take place on the transmission 

providers’ OASIS and that all 

information should be retained by the 

transmission provider. PGP submits that 

redispatch bids should be explicitly 

added to the Commission’s Electric 

Quarterly Reports filing requirements if 

not already required. 

1146. Constellation argues that the 

Commission should require each 

transmission provider to post two 

values to the market on its OASIS site, 

in order to enhance transparency: 

historical costs of redispatch at certain 

specified flowgates (perhaps those most 

congested historically) and real-time 

redispatch costs at the same flowgates. 

Constellation submits that each 

transmission provider engages in 

redispatch and thus can readily 

ascertain the cost of redispatch at 

various locations. Constellation argues 

that posting such costs will enable 

transmission customers to more 

accurately assess the potential costs of 

redispatch prior to deciding to incur 

redispatch costs. Constellation adds that 

the customer receiving redispatch 

should be obligated to pay the actual 

costs of redispatch, regardless of the 

costs reflected in the postings, which, 

Constellation contends, should reflect 

the transmission provider’s most 

accurate and up-to-date information. 

1147. Williams believes that 

Transparent Dispatch Advocates’

redispatch proposal offers a partial 

remedy to transmission congestion 

caused by insufficient infrastructure and 

undue discrimination. Williams 

proposes that affiliate and third-party 

generators submit either a preestablished rate structure or formulary 

pricing methodology prior to the 

provision of redispatch service. 

Williams states the primary 

implementation impediment to greater 

transparency of redispatch cost 

information is the accuracy and 

availability of redispatch costs. 

1148. BP Energy submits that posting 

the costs of redispatch is not the same 

as posting operational cost curves of 

specific generating units. BP Energy 

adds that, given the availability of 

redispatch costs, there is no reason to 

post the differential in unit-specific 

costs as a supplement to marginal prices 

posted at significant locations 

throughout the control area. PGP states 

that there is no need to establish 

markets to provide real-time redispatch. 

Rather, PGP asserts that limited 

protocols can be established for specific 

locations or types of congestion that 

may be directly relieved via redispatch. 

PGP believes that the Commission 

should avoid establishing detailed rules 

governing redispatch protocols, but 

rather should permit regional practices 

to be developed that result in ‘‘just and 

reasonable’’ charges for redispatch 

service. 

1149. In its reply comments, Southern 

states that requiring vertically integrated 

utilities to post their real-time marginal 

costs of electricity would be 

discriminatory and violate the Trade 

Secrets Act.702 Southern states that 

RTOs do not make public the marginal 

costs of the utilities participating in 

their markets, thus requiring other 

transmission providers to do so would 

be discriminatory. Southern states that 

marginal costs information is 

commercial or financial information 

protected by federal statute that if 

released would put it at a competitive 

disadvantage and harm its customers by 

allowing competing generators to price 

their power just below the published 

marginal costs. 

1150. Several parties assert that the 

TDA proposal would require the posting 

of vertically integrated utilities’

generation costs and thus would 

provide competitors and buyers with 

commercially-sensitive information.703


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704E.g., Entergy Supplemental, Community 

Power Alliance Supplemental, Southern 

Supplemental, Duke Supplemental and South 

Carolina E&G Supplemental. 

705Entergy refers to the following language: 

(1) The Commission shall exempt from disclosure 

information the Commission determines would, if 

disclosed, be detrimental to the operation of an 

effective market * * *; and (2) [i]n determining the 

information to be made available under this section 

and the time to make the information available, the 

Commission shall seek to ensure that consumers 

and competitive markets are protected from adverse 

effects of potential collusion and other 

anticompetitive behaviors that can be facilitated by 

untimely public disclosure of transaction-specific 

information. 

706Ameren raises several questions to this effect: 

Does the transmission provider estimate cost effect 

across all market LMPs or just the congested points? 

Should the analysis take into account credits and 

adjustments to which some participants may be 

entitled? For what period should the transmission 

provider provide this estimate? For those 

transmission providers within a centralized market, 

how should they treat market costs such as losses 

or RSG (Revenue Sufficiency Guarantee in MISO) 

in calculating the redispatch cost? 

Many of these parties assert that posting 

a utility’s incremental costs publicizes 

the price at which the utility elects to 

operate resources rather than purchase 

from a third-party.704 EEI and South 

Carolina E&G assert that making this 

information public may adversely affect 

competition and markets. Duke argues 

that having the transmission provider 

post daily and hourly generator costs 

assigns it responsibilities that are 

beyond the typical transmission 

function. Duke urges the Commission to 

consider voluntary alternatives to 

resource-specific cost information that 

would divulge competitively-sensitive 

data. SEARUC argues that any 

incremental transparency improvements 

not be implemented in such a manner 

as to make competitively sensitive 

information available to the public on 

an inconsistent basis. Nevada 

Companies assert that the requirement 

to make such information publicly 

available to the transmission provider 

would have to be imposed upon all 

generators, including independent 

power producers, so that such 

information would lose the value it 

derives from not being publicly known. 

1151. Entergy argues that the 

Commission is statutorily prohibited 

from requiring the disclosure of 

information that undermines fair 

competition under the electric market 

transparency provisions in sections 

220(b)(1) and (2) of the FPA.705 South 

Carolina E&G submits that the TDA 

proposal is inconsistent with this 

provision of the FPA. Southern further 

contends that mandating that 

transmission providers post and offer 

their generation on an at-cost basis, 

while allowing third party generators to 

submit bid prices would also be 

discriminatory. TAPS asserts that the 

proposed real-time disclosure of bid and 

cost information runs contrary to the 

Commission’s policy of a 6-month delay 

for release of bid information. 

1152. NRECA asserts that the 

Transparent Dispatch Advocates fail to 

explain why transmission providers 

coordinating with third parties or 

neighboring transmission providers will 

not run afoul of anti-trust and collusion 

concerns that they are colluding in price 

setting; and how to verify providers are 

selecting the lowest bid unless they are 

required to post all third party generator 

bids as well as their own or their 

affiliates’ cost of providing the service. 

1153. Ameren asserts that the existing 

OATT contains requirements for 

information to be posted by 

transmission providers, and does not 

believe that additional posting ought to 

be required. Ameren provides several 

recommendations were the Commission 

to adopt some or the entire TDA 

proposal. First, Ameren asserts that 

there are many different ways to 

estimate this cost and, in order to avoid 

the creation of competing methods for 

estimating redispatch costs, the 

Commission must consider and provide 

guidance on several questions.706

Second, so that transmission providers 

are not disadvantaged by this new 

obligation, Ameren urges the 

Commission to develop detailed 

requirements, including uniform 

timelines for posting, guidelines for 

estimating cost, and inclusion of all 

dispatchable generation in the relevant 

footprint. Ameren further argues that 

posting only the difference in costs 

would not address the potential for 

anticompetitive impacts. Finally, 

Ameren contends that the Commission 

may wish to consider implementing the 

changes only on an interim basis, then 

to observe whether there is any market 

benefit or any competitive harm as a 

result of the new requirements. 

1154. Duke believes that the posting 

of hourly redispatch costs would create 

near-constant off-OASIS 

communications between the 

transmission provider and merchant 

function employees, which, Duke 

asserts, would raise Standards of 

Conduct concerns. 

1155. NRECA argues that allocated 

costs may vary significantly regardless 

of methodology, which devalues the 

posting of costs. North Carolina 

Commission argues that publishing 

indicative redispatch costs in real time 

would require a determination as to 

how such costs are determined and 

whether each component of such costs 

are appropriately charged to customers. 

Commission Determination 

1156. After careful consideration of 

the comments of the parties, we adopt 

a posting obligation that balances 

several competing considerations. First, 

we agree with Transparent Dispatch 

Advocates and supporting parties that 

the increased availability of information 

regarding redispatch costs can benefit 

consumers and increase the efficient use 

of the grid. Second, we are cognizant, 

however, that increased posting and 

reporting can impose cost burdens on 

transmission providers or otherwise 

harm market participants. For example, 

the reporting obligations can reveal 

confidential information that could 

harm market participants or increase the 

cost of serving native load customers. 

We also recognize that the posting or 

reporting obligation should be 

reasonably tailored to provide useful 

information to consumers without, at 

the same time, imposing unnecessary 

burdens on transmission providers, 

either in the frequency of the posting 

obligation or the scope of information 

provided. 

1157. In balancing these 

considerations, we will, as explained 

further below, adopt a requirement that 

transmission providers post certain 

redispatch cost information associated 

with the existing redispatch services 

that must be provided under the pro 

forma OATT. We find that providing 

customers with additional transparency 

and greater information regarding the 

cost of congestion, will facilitate their 

consideration of planning redispatch 

options which in turn will provide for 

more efficient use of the grid. We stress, 

however, that this posting requirement 

relates only to the existing redispatch 

services required under the pro forma 

OATT; it does not expand those service 

obligations. The primary purpose of the 

posting requirement is to ensure that all 

customers have access to this 

information, not only the customer 

receiving the redispatch service. 

1158. Moreover, the costs of the 

dynamic posting requirement proposed 

by Transparent Dispatch Advocates 

outweigh the benefits of such a 

requirement. Transparent Dispatch 

Advocates propose that the posting 

requirement be limited to specified 

congestion locations within and at the 

border of each transmission provider’s 

system. Transparent Dispatch Advocates 

have not proposed ex ante criteria to 

determine which flowgates would 

require posting. In fact, some members 

of the Transparent Dispatch Advocates 

coalition would have the posting 

requirement apply to all transmission 

facilities, whether or not they were 


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707The relevant reliability redispatch costs for 

posting purposes are those costs the transmission 

provider invoices network customers based on a 

load ratio share pursuant to section 33.3 of the pro 

forma OATT. The transmission provider need not 

perform new calculations of out-of-merit dispatch 

costs; rather the reliability redispatch invoices 

should form the basis of information from which 

the transmission provider determines monthly 

average reliability redispatch costs. 

708For example, if reliability redispatch is used 

by the transmission provider to prevent curtailment 

of 10 MW of transmission provider or network 

customer load for 5 hours during the month across 

flowgate A, the transmission provider would use 50 

MWh as the divisor to determine the monthly 

average cost of redispatch for flowgate A. 

709This is not a new calculation for the 

transmission provider because the transmission 

provider must determine the redispatch costs to 

know whether to charge higher of the embedded 

rate or the redispatch costs. 

congested and whether or not customers 

were seeking service over those 

facilities. Such an open-ended 

obligation to post costs for all facilities 

on a transmission provider’s system 

would unnecessarily impose 

uncertainties and unbounded 

administrative costs on transmission 

providers. Additionally, depending on 

the frequency of publication and the 

method used to calculate the estimates, 

the publication of these estimates could 

reveal sensitive confidential information 

about transmission providers’

generation costs that would likely harm 

existing markets and native loads. There 

is no simple formula for estimating the 

costs that would fully mask this 

confidential information and at the 

same time provide practical information 

about the costs of redispatch. 

1159. While we agree that 

transparency can benefit customers, 

Transparent Dispatch Advocates have 

not demonstrated the benefits of its 

posting requirement to customers 

seeking reliability or planning 

redispatch. Transparent Dispatch 

Advocates would have transmission 

providers frequently post an estimate of 

the cost of the next increment of 

redispatch. Customers seeking 

redispatch would not know the actual 

costs customers paid for redispatch. Nor 

would they be able to apply the estimate 

of cost to their transactions since most 

transactions would involve more than a 

single increment of redispatch service 

and there might be multiple redispatch 

transactions over a single transmission 

facility. Thus the estimate would only 

be of value to the marginal customer 

taking a small amount of redispatch 

service. Transmission providers would 

expend time and money determining 

the correct formula to use to estimate 

costs, collecting data for the inputs to 

the calculation and frequently posting 

estimates throughout each day that 

could have little or no correlation to the 

actual costs a transmission customer 

would pay for the redispatch service. 

1160. Third party participation in 

redispatch is one of the benefits 

Transparent Dispatch Advocates point 

to in support of its proposed posting 

requirement. Transparent Dispatch 

Advocates would have transmission 

providers act as the conduit for service 

from third party redispatch providers, 

collecting from customers and paying 

third party providers. As described 

above, we are allowing third party 

participation in planning redispatch 

without requiring transmission 

providers to act as bill collectors for 

third party redispatch providers or 

requiring coordination agreements 

among each transmission provider and 

all potential third party providers. This 

OASIS modification, described above, 

will provide third parties seeking to 

provide redispatch with the opportunity 

to frequently update the price of their 

offers as suggested by Transparent 

Dispatch Advocates. 

1161. We do believe, however, that 

information regarding actual redispatch 

costs should be made more widely 

available. Currently, when a 

transmission provider provides 

reliability or planning redispatch, the 

associated cost information is provided 

only to the customer receiving the 

service through its invoices. This 

ignores the fact that information 

regarding the cost of redispatch can 

benefit all customers and increase the 

efficient use of the grid. We therefore 

find that it is no longer just, reasonable 

and not unduly discriminatory to limit 

the provision of this information only to 

the individual customers receiving the 

service. 

1162. Accordingly, to provide greater 

availability of redispatch information, 

the Commission adopts certain 

additional posting requirements for 

transmission providers. Specifically, we 

direct each transmission provider to 

post on OASIS its monthly average cost 

of redispatch for each internal congested 

transmission facility or interface over 

which it provides redispatch service 

using planning redispatch or reliability 

redispatch under the pro forma 

OATT.707 Additionally, to demonstrate 

the range of redispatch costs each 

month, the Commission directs 

transmission providers to post a high 

and low redispatch cost for the month 

for each of these same transmission 

constraints. The transmission provider 

shall calculate the monthly average cost 

in $/MWh for each congested 

transmission facility by dividing 

monthly total redispatch costs (at the 

facility) by the total MWhs that would 

otherwise be curtailed (at the facility) in 

the month absent the redispatch.708

Transmission providers shall post 

internal constraint or interface data for 

the month if any planning redispatch or 

reliability redispatch is provided during 

the month, regardless of whether the 

transmission customer is required to 

reimburse the transmission provider for 

those exact costs. Thus, if the 

transmission customer pays for 

redispatch pursuant to a negotiated 

fixed rate, the transmission provider is 

required to post and calculate the 

monthly average redispatch costs and 

the high and low costs in the month 

even though the transmission provider 

will bill the customer the fixed rate. The 

same posting requirement applies if the 

customer is paying a monthly ‘‘higher 

of’’ rate.709 The transmission provider 

shall post this data on OASIS as soon as 

practical after the end of each month, 

but no later than when it sends invoices 

to transmission customers for 

redispatch-related services. We direct 

transmission providers to work in 

conjunction with NAESB to develop 

this new OASIS functionality and any 

necessary business practice standards. 

1163. There are several benefits to this 

posting requirement. First and foremost, 

it will give customers fairly current 

information regarding the cost of 

redispatch of the congested 

transmission facilities over which 

redispatch is provided, presumably 

some of the most congested facilities on 

transmission providers’ systems. 

Second, it will limit posting only to 

those congested transmission facilities 

over which redispatch has actually been 

sought and granted and for which 

redispatch charges have been billed to 

customers. This addresses commenters’

concerns about the posting of 

information that is valuable only 

hypothetically. Third, because we 

require the posting of average redispatch 

costs, not real-time redispatch costs or 

real-time system lambda or system 

incremental costs, it will not be harmful 

to native load or reveal otherwise 

competitively sensitive information. 

1164. Finally, in addition to the above 

posting requirement, we note that, as 

part of the transmission planning 

provisions adopted in this Final Rule, 

we are providing customers with a right 

to request a study of a defined number 

of congested transmission facilities on 

an annual basis. This will provide 

customers an additional opportunity to 

evaluate redispatch costs, including 

costs for those congested transmission 

facilities for which redispatch service 

has not been granted. 


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710E.g., MidAmerican, Public Power Council, 

Northwest IOUs, Xcel, Powerex Reply, PPL, and 

Seattle Reply. 711Order No. 888–A at 30,235–36. 

c. Other Requested Service 

Modifications 

NOPR Proposal 

1165. In the NOPR, the Commission 

summarized requests for various new 

services made in response to the NOI. 

The Commission’s proposed solutions 

evaluated solely the planning redispatch 

and conditional firm options. 

Comments 

1166. Commenters make several 

suggestions with regard to additional 

services or modifications to existing 

services. Most popular among the 

suggested new services is long-term, 

seasonally-shaped firm point-to-point 

service. Several commenters support 

this service for circumstances in which 

the transmission provider determines 

that the requested service is available 

during some, but not all, months of each 

year of a single or multiyear request.710

Commenters suggest that the long-term, 

seasonally-shaped service would 

provide an option for the transmission 

customer in lieu of costly upgrades 

without the operational difficulties of 

conditional firm service. In its reply 

comments, Powerex states that this 

product would have less of an adverse 

impact on existing firm rights holders. 

Northwest IOUs propose that the 

transmission customer pay the longterm point-to-point transmission service 

rate prorated for the portion of the year 

for which it receives the service. Public 

Power Council states that the 

transmission customer would be free to 

purchase non-firm or secondary service 

for the periods when firm service 

through the seasonally-shaped service 

was unavailable. Northwest IOUs argue 

that ‘‘cream-skimming’’ is avoided by 

processing only requests for long-term 

service and having the transmission 

provider determine the availability of 

the service. 

1167. Powerex supports the 

implementation of a long-term non-firm 

point-to-point service. Tacoma believes 

priority non-firm or partial firm 

transmission services are alternatives to 

planning redispatch. Entegra proposes 

an additional service that would allow 

the customer, in the event of a 

constraint, to agree to either pay for 

redispatch or have its service curtailed. 

In contrast to these request for new 

services, TranServ states that simplified 

services and a reduction in the number 

of services would increase the 

transparency and fluidity of electricity 

trading. 

1168. MidAmerican urges the 

Commission to allow for dynamic 

scheduling service between control 

areas on a case-by-case basis, by 

including and pricing the service in the 

service agreement. MidAmerican states 

that this service would be similar to 

point-to-point service, but would allow 

the transmission customer to 

dynamically monitor its loads in 

neighboring control areas and dispatch 

its own remote resource to meet the load 

fluctuations in load pockets served by 

other transmission providers. 

MidAmerican further states that this 

new service is necessary in the Western 

Interconnection because neither pointto-point nor network service meets the 

needs of loads that are not confined to 

a single geographic area served by a 

single transmission provider. 

1169. Barrick states that the 

Commission should require 

transmission providers to confirm the 

availability of secondary service for 

network customers on a monthly or 

quarterly basis so that network 

customers can plan ahead for the use of 

secondary service. In its reply 

comments, Seattle supports the 

development of short-term redispatch 

service, currently under discussion for 

provision in the Pacific Northwest. 

TranServ requests that the Commission 

clarify whether sequential reservation of 

12 consecutive months of monthly firm 

service is long-term service. TranServ 

requests that the Commission direct the 

development of business practices by 

NAESB to allow customers to designate 

minimum term and capacity for partial 

interim service, similar to the practice 

employed by Bonneville. 

Commission Determination 

1170. The Commission rejects the 

requests to order new services or 

modifications to existing services 

suggested by commenters. We believe 

that the modifications to point-to-point 

transmission service adopted herein 

best address the issues raised by these 

requests. The planning redispatch and 

conditional firm options provide a 

means of remedying undue 

discrimination, and increasing 

transparency and access to the grid by 

point-to-point customers. We note that 

there is considerable overlap between 

these options and the new services 

suggested by commenters. However, we 

find that the introduction of the 

requested new services may create 

greater complexities than those present 

in the planning redispatch and 

conditional firm options. For example, 

several commenters propose a long-term 

seasonally shaped firm point-to-point 

service as a superior option to the 

conditional firm service. However, 

requestors have not adequately 

addressed concerns about the service, 

including the potential for hoarding 

transmission and the reliability issues 

related to evaluating the availability of 

the service or granting the service over 

many years. A seasonally shaped service 

could exacerbate the lumpiness of 

transmission investment by preventing 

customers willing to pay for 

transmission upgrades from obtaining 

all twelve months of service. While we 

will not reduce the number of services 

required as suggested by TranServ, the 

Commission must limit the number of 

new services adopted and modifications 

to existing services to a reasonable 

number that transmission providers can 

reliably implement. For these reasons, 

we decline to adopt any additional 

proposals or modifications to firm 

point-to-point service beyond those 

directed above in this Final Rule. Of 

course, transmission providers remain 

free to voluntarily propose additional 

services that are consistent with or 

superior to the pro forma OATT, as 

modified by this Final Rule. 

1171. The Commission rejects the 

request to adopt long-term non-firm 

service because there is no indication 

that customers would find such a 

service useful and it would be 

inconsistent with the policy in the pro 

forma OATT that values firm service 

over non-firm service. 

1172. MidAmerican requests that the 

Commission allow a point-to-point 

service that would let a transmission 

customer monitor its load and dispatch 

its remote resources to meet load 

fluctuations. In Order No. 888–A, the 

Commission clarified that this type of 

dynamic scheduling was not mandated 

Order No. 888, but that nothing in Order 

No. 888 precludes a transmission 

provider from offering it as a separate 

service.711 Thus, MidAmerican may 

propose such a service pursuant to an 

FPA section 205 filing with the 

Commission, and we will consider it, as 

we would any new service proposal, on 

a fact-specific, case-by-case basis. 

1173. Barrick requests that the 

Commission require the confirmation of 

the availability of secondary service for 

network customers on a monthly or 

quarterly basis so that network 

customers can plan ahead for the use of 

secondary service. As we stated in the 

NOPR, secondary network service refers 

to transmission service for network 

customers from resources other than 

designated network resources and is 

provided on an ‘‘as available’’ basis. 

Since the secondary service is provided 


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712See pro forma OATT section 1.18 (defining 

long-term firm point-to-point transmission service 

as service with a term of one year or more). 

713See IES Utilities, Inc., 81 FERC ¶ 61,187 at 

61,833–34 (1997), reh’g denied, 82 FERC ¶ 61,089, 

aff’d on other grounds sub nom. Wisconsin Public 

Power Inc. v. FERC, No. 98–61,089, 1999 U.S. App. 

LEXIS 3998 (Feb. 23, 1999) (unpublished opinion) 

(adopting peak and off-peak pricing to hourly nonfirm transmission service); see also New York State 

Electric & Gas Corp., 92 FERC ¶ 61,169 at 61,593–

94 (2000) (approving application of the IES Method 

for time-differentiated hourly non-firm rate design), 

order on reh’g, 100 FERC ¶ 61,021 (2002). 

714E.g., Ameren, Arkansas Commission, 

Bonneville, BP Energy, Constellation, FirstEnergy, 

MidAmerican, MISO/PJM States, Morgan Stanley, 

Nevada Companies, Newmont Mining, 

NorthWestern, Pinnacle, PPL, CREPC, and Suez 

Energy NA. 

715E.g., Bonneville, Pinnacle (noting Arizona 

Public Service Company’s adoption of the service), 

PNM–TNMP, and WAPA (in its Desert-Southwest 

region). 

716E.g., Arkansas Commission, BP Energy, 

FirstEnergy, Morgan Stanley, Pinnacle, PNMTNMP, and PPL. 

717 e.g., APPA, Duke, EEI, MISO, and Southern. 

on an as available basis, Barrick’s 

request seeks to allow secondary 

network service to pre-empt firm uses of 

the system, such as short-term firm 

point-to-point service, for what is a less 

than firm service. Barrick has not clearly 

articulated why this proposal is 

necessary to prevent the exercise of 

undue discrimination or why service 

from designated network resources 

would not meet its need for firmer 

secondary service. Thus, we reject 

Barrick’s request. 

1174. With regard to Seattle’s support 

for redispatch being developed in the 

Pacific Northwest, we believe that this 

type of redispatch shares many of the 

attributes of the Transparent Dispatch 

Advocates proposal rejected above. 

Although we acknowledge that market 

mechanisms that provide hour-ahead or 

real-time redispatch for all transmission 

customers can provide benefits to 

customers and efficient use of the 

transmission grid, for the reasons stated 

in the prior section, we will not require 

in this Final Rule that all transmission 

providers implement such market 

mechanisms. We note that nothing 

prevents the Commission from 

reviewing proposals for such market 

mechanisms on a case-by-case basis. We 

note that the conditional firm and 

planning redispatch options adopted in 

this Final Rule will provide some of the 

flexibility Entegra seeks. Customers 

taking service under these options will 

be able to choose, when executing the 

service agreement, between curtailment 

and redispatch. 

1175. Also, the Commission clarifies 

for TransServ that twelve months of 

consecutive monthly firm service, 

where the term of any particular 

monthly service agreement is for less 

than a year, is not long-term service.712

The Commission rejects TranServ’s 

request that NAESB develop particular 

business practices regarding partial 

interim service as TranServ has not 

shown a need for such a requirement. 

1176. The Commission continues to 

encourage transmission providers to 

propose other services that are 

consistent with or superior to the pro 

forma OATT that meet customers’ needs 

and make more efficient use of the 

transmission system. We will not 

mandate that transmission providers 

provide any service other than the 

services set forth in the pro forma OATT 

since they may not be applicable in all 

circumstances. However, if transmission 

providers seek to provide any 

modifications to the required pro forma 

OATT services or new services, they 

may submit an FPA section 205 filing to 

propose such modifications and the 

Commission will evaluate such 

proposals on a case-by-case basis. 

2. Hourly Firm Service 

NOPR Proposal 

1177. In the NOPR, the Commission 

proposed to add point-to-point hourly 

firm service to the pro forma OATT. The 

Commission stated its belief that adding 

this service would eliminate a barrier to 

the development of markets and thereby 

decrease opportunities for undue 

discrimination. The Commission further 

stated that the concerns expressed in 

Order No. 888 regarding the unduly 

discriminatory effects of hourly firm 

service have proven unfounded. 

Consistent with our precedent, the 

Commission proposed to use the ‘‘IES 

Method’’ to price hourly firm service 

and apply different pricing based on 

whether the service is taken during peak 

or off-peak hours.713 The Commission 

explained that this pricing method 

would ensure that hourly firm 

customers pay a fair share of the costs 

of the transmission system. 

1178. The Commission proposed 

allowing transmission customers to 

batch requests and schedules for hourly 

firm service that will be provided 

within the same calendar day. 

Schedules for firm hourly service, like 

all other firm schedules, would be due 

by 10 a.m. the day before the service is 

to commence. The Commission also 

proposed that, consistent with other 

durations of service, the confirmation 

period for hourly firm service specified 

in section 13.2 of the pro forma OATT 

would allow longer term requests for 

service to preempt shorter hourly firm 

requests for service until one hour 

before the commencement of hourly 

firm service. 

Comments 

1179. Commenters are split on 

whether to require hourly firm service. 

Varied interests express some support of 

the requirement, while mostly IOUs, 

cooperatives, and public power 

providers oppose the requirement. 

Supporters, which include several 

entities that currently offer hourly firm 

service, foresee increased use of 

transmission facilities and market 

efficiencies. Chief among the arguments 

cited by those objecting to the required 

service is the potential adverse effect on 

those serving native load or taking 

longer term service due to increased 

frequency of curtailments. Other 

objections to the required service 

include reliability concerns and the 

unjustified curtailment priority that 

would be afforded to short-term 

customers that have not financially 

committed to long-term grid service. To 

the extent hourly firm service is 

required, commenters generally support 

use of the IES Method for pricing, 

although some commenters ask the 

Commission to allow pricing to vary 

according to regional practice. As for 

batching and scheduling, many parties 

request that the Commission clarify 

specific details of each of these 

proposals to prevent future disputes. 

Mandatory Hourly Firm 

1180. Various commenters state their 

general support of, or non-opposition to, 

the proposal to require hourly firm 

service.714 Among those who support it, 

several state that they already supply 

the service themselves.715 Such 

commenters argue that hourly firm 

service would decrease opportunities 

for undue discrimination, enhance the 

customer’s ability to participate in the 

real-time energy markets, encourage 

trade and marketing liquidity, increase 

firm uses of the grid, allow greater 

customer choice, increase efficiencies in 

wholesale markets, and help maximize 

use of existing transmission facilities.716

WAPA states that its experience 

indicates that the current provisions for 

preempting shorter-term transmission 

service with longer-term service, as 

codified in OATT section 13.2, 

adequately serve to discourage 

speculative hoarding of hourly capacity. 

1181. Numerous commenters 

objecting to the proposed service cite 

the effect of curtailment on customers 

taking network or longer term service, 

especially in the service of native 

load.717 Specifically, they argue that the 

inclusion of an additional short-term 

firm service would increase the 


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718 e.g., MISO and Southern. 

719 e.g., APPA, NRECA, and Southern. 

720 e.g., Southern. 

721 e.g., LDWP, MISO, Southern, TAPS, TDU 

Systems. 

722E.g., ELCON, FirstEnergy, Powerex, and South 

Carolina E&G. 

723 e.g., APPA, NRECA, Southern, and TAPS. 

724E.g., APPA, Duke, East Texas Cooperatives, 

EEI, Imperial, LDWP, LPPC, Northwest IOUs, 

NRECA, PJM, Southern, and TDU Systems. 

likelihood that longer-term service 

would be curtailed and degrade the 

reliability of service to native load, since 

all firm service (point-to-point and 

network), regardless of duration, would 

be curtailed pro rata. Objecting 

commenters argue that such a result is 

unfair to customers that have made a 

long-term commitment to taking service, 

including expanding the system;718

inconsistent with FPA section 217(b)(4), 

which requires the Commission to 

promote the availability of transmission 

for native load service;719 and 

inconsistent with the Commission’s 

commitment in the NOPR to maintain 

existing native load protections.720

1182. Although transmission 

providers plan for their native load 

needs when calculating ATC, Imperial 

argues that they cannot always 

accurately predict these needs. Imperial 

states that transmission providers have 

been able to rely on the release of 

unscheduled capacity when balancing 

their schedules to meet fluctuating 

needs (such as during heat waves). In 

view of the decline in transmission 

infrastructure relative to load 

throughout the country, NRECA objects 

to the reduction in ATC that would 

result from dedicating transmission 

capacity to hourly firm service. NRECA 

argues that designated network 

resources may no longer be regarded as 

such because firm transmission to 

support them is not available on 

constrained transmission systems (i.e., 

most transmission systems). If hourly 

firm service is to be required, Imperial 

proposes also requiring transmission 

providers to make available all but 20 

percent of non-reserved transmission as 

firm so that non-firm service will be 

available for the use of network 

customers and native load providers. 

1183. Southern argues that the 

provision of hourly firm service would 

require the transmission provider to 

predict the exact hour on which 

expected peak conditions will occur in 

order to be able to post the amount of 

hourly firm service that will be available 

for each hour of a given day. If system 

conditions then change, Southern 

continues, reliability could be placed in 

jeopardy, which would result in longterm service being curtailed. Southern 

also argues that the provision of this 

hourly firm service would complicate 

real-time operations and negatively 

impact reliability since, if curtailments 

on a specific path prove necessary, it is 

more difficult to curtail a large number 

of transactions on a very short-term 

notice. 

1184. Many argue that the 

justifications provided in Order No. 888 

for not requiring this service remain 

valid, such as the argument that the 

service will invite cream skimming.721

MISO sees a likelihood that an ‘‘hourly 

priority war’’ would ensue on 

constrained interfaces between firm and 

non-firm requests and that resolving 

these conflicts would be time 

consuming and stretch its resources. 

MISO argues that an hourly firm 

product would degrade the value of 

non-firm service and that the 

introduction of this new, logistically 

challenging service, further compounds 

the task of rooting out undue 

discrimination. MISO argues that the 

proposed mandatory introduction of 

this service will have serious adverse 

implications for many functioning 

RTOs. MISO contends that hourly firm 

service should remain strictly optional 

for RTOs arguing that weighing the pros 

and cons of this new service can best be 

addressed within each RTO’s 

stakeholder process. 

1185. TVA argues that hourly firm 

reservations would likely end up being 

bumped by requests for longer service 

(such as daily firm), consuming valuable 

transmission provider staff time and 

resources on administrative tasks with 

no real benefit and potentially 

significant costs. Similarly, Southern 

argues that hourly firm service would 

likely result in the transmission 

provider receiving less revenues 

(because fewer customers would take 

daily firm service) while incurring 

higher costs (due to implementation 

complexities), the net effect of which 

would raise OATT charges. 

1186. Among commenters offering 

qualified support for mandatory hourly 

firm service,722 ELCON and FirstEnergy 

ask the Commission to monitor the use 

of this service and to reconsider its 

continued need if it impairs the quality 

or availability of long-term firm 

services. Powerex argues that hourly 

firm point-to-point service could 

increase opportunities for undue 

discrimination unless the conditions 

under which the non-firm transmission 

service can be interrupted are clarified. 

South Carolina E&G argues that the 

Commission should give the service a 

lower curtailment priority than any 

longer term firm service (citing as 

support the lower reservation priority 

for short term firm service in section 

13.2(iii)) and adopt the proposal to 

require that hourly firm service be 

scheduled the day before service is to 

commence. 

1187. Duke explains that the current 

10 a.m. deadline for firm schedules 

need not be enforced in the absence of 

hourly firm service and often is not 

enforced (with transmission providers 

acting on a comparable basis in waiving 

the deadline). Thus Duke identifies as a 

drawback to the addition of hourly firm 

service the likelihood that transmission 

providers will enforce the 10 a.m. 

deadline and thereby reduce existing 

flexibility. 

1188. Some commenters objecting to 

the new service requirement argue that, 

if the Commission retains this service, 

certain modifications should be 

made.723 These modifications include: 

giving the service a lower curtailment 

priority, pricing it at a premium above 

the IES methodology, requiring that the 

firm hourly postings be based upon the 

daily firm ATC (with the additional 

capacity that might be available in 

‘‘shoulder’’ hours of the day being made 

available only as hourly non-firm), and 

giving secondary network service a 

higher priority over hourly firm. Duke 

argues on reply that, if the Commission 

determines that hourly firm service 

should be required, a technical 

conference should be held to develop 

appropriate, workable tariff language in 

light of the implementation issues 

raised by commenters. 

Voluntary Hourly Firm Service 

1189. Various commenters ask that 

hourly firm service not be required and, 

instead, continue to be allowed on a 

voluntary basis by willing transmission 

providers.724 These commenters 

generally argue that the service’s effect 

on reliability, curtailment priority, 

longer term service, transmission 

expansion, and the ability to serve 

native load counsels against mandating 

the service. NRECA argues that hourly 

firm service would unduly interfere 

with the ability of network customers 

(and the transmission provider on 

behalf of its native load customers) to 

use secondary network service, which is 

offered only on an ‘‘as available’’ basis 

and therefore would have a lower 

reservation and curtailment priority 

than hourly firm service. 

1190. NRECA notes that the Western 

Interconnection, where hourly firm 

service has proven to be a useful 

product, differs from the Eastern 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12419 

725E.g., Ameren, EEI, NorthWestern, PGP, and 

PNM–TNMP. 

726E.g., Northwest IOUs, Public Power Council, 

and CREPC. 

727E.g., Ameren, Duke, NorthWestern, PNM–

TNMP, and WAPA. 

728E.g., Bonneville, Southern, and TVA. 

729E.g., Public Power Council and Tacoma. 

730E.g., MidAmerican, Northwest IOUs, Public 

Power Council, and CREPC. 

Interconnection in a number of respects, 

in particular, by virtue of extensive 

reliance on point-to-point service by 

LSEs to serve native load. For this 

reason, NRECA continues, public utility 

transmission providers should only be 

allowed to voluntarily offer hourly firm 

transmission service if the service is 

available equally to all transmission 

customers and the new service does not 

undermine the quality of, and flexibility 

of, the transmission provider’s existing 

network service (including secondary 

network service) and point-to-point 

transmission service. NRECA also 

requests that the Commission clarify 

that the only circumstance in which 

hourly firm service could be offered 

would be if daily service were not being 

fully used. 

1191. Northwest IOUs suggest that the 

Commission develop standardized 

point-to-point hourly firm service 

provisions for the voluntary provision of 

this service by those transmission 

providers that determine such service 

would be appropriate to offer on their 

systems. TDU Systems argue that the 

Commission should condition approval 

of an hourly service on requirements 

that a lower curtailment priority is 

established for hourly firm service than 

other firm services, including secondary 

network service; and, it may only be 

sold in the hour preceding the start of 

service to ensure that hourly service 

would not impede the provision of 

service to other firm services, including 

secondary network service. In light of 

comments, Powerex abandoned its 

initial conditional support for the 

proposal to support voluntary provision 

of the service. 

Alternative Proposals 

1192. PJM recommends adding a 

service similar to PJM’s non-firm willing 

to pay congestion (NF–WPC) service 

which may serve the same purpose as, 

and be an alternative to, hourly firm 

service. NF–WPC service would be 

evaluated for ATC and curtailed by 

transmission customers if the effective 

price of congestion were too high. Thus, 

NF–WPC service will result in a 

reduction in all TLR curtailments. To 

add this service to the OATT, PJM 

explains, all transmission providers 

with control over dispatch would have 

to provide a transparent means for 

redispatch to clear congestion and 

maintain reliability on either side of a 

border. 

1193. Xcel argues that it is possible 

that hourly firm service would not be 

needed if the existing OATT were 

clarified as it relates to priority of nonfirm service. Xcel proposes that the 

Commission could clarify that non-firm 

service is not interruptible during the 

hour due to other non-reliability driven 

requests, but rather at the start of the 

next hour, provided sufficient 

scheduling notice is given. Xcel 

continues that this clarification would 

also stipulate that non-firm service (and 

all other types of service) may be 

curtailed without notice at any time for 

reliability reasons. 

Pricing 

1194. Many commenters support the 

Commission’s proposal to use the IES 

Method to price hourly firm service.725

Several commenters suggest that the 

Commission allow transmission 

providers to define their own peak and 

off-peak hours under the IES 

methodology, with some suggesting that 

it should be allowed as a regional 

variation to account for the different 

peak times in regions such as the 

WECC.726 East Texas Cooperatives asks 

the Commission to require that revenue 

from hourly firm service be applied as 

a credit to network service revenue 

requirements like other point-to-point 

services. PGP supports the IES Method, 

but recommends that the Commission 

be open to other approaches. 

Reservations, Scheduling, Preemption 

and Right of First Refusal, Batching 

1195. Some commenters support the 

proposed reservation or scheduling 

requirements for hourly firm service.727

Others commenters express concerns 

regarding, or object to, this aspect of the 

hourly firm proposal.728 As discussed 

below, several commenters suggest 

modifications to different components 

of the proposal. 

1196. Some commenters state that 

hourly firm should be a means of selling 

unused capacity in hours not purchased 

for longer-term transactions and, as a 

result, it will be important to establish 

a sequencing for sales that accomplishes 

this so that cream skimming does not 

occur.729 Tacoma recommends that the 

Commission establish hourly firm 

service as the lowest priority in the 

service request queue. Tacoma also 

suggests that the Commission limit the 

purchase of hourly firm in such a way 

as to assure that the purchase is not an 

attempt to manipulate a market, such as 

making the service available only to 

LSEs, which Tacoma states would 

ensure that capacity is utilized to meet 

a real market need. 

1197. SPP urges the Commission to 

apply the same reservation deadline to 

hourly firm as used for daily firm 

service in order to make the service 

easier to administer (and limit the 

impact on non-firm service). Bonneville 

also suggests that reservation timing 

requirements be the same as those for 

hourly non-firm service and, with 

respect to competing reservations, 

hourly firm service be classified as 

Short-Term Firm. TVA notes that 

although the scheduling deadline for 

service is 10 a.m. the day before service 

is to commence, the NOPR also states 

that longer-term requests may preempt 

shorter requests until one hour before 

the commencement of service. TVA sees 

an inconsistency in that it appears firm 

service can be reserved and scheduled 

after 10 a.m. on the day prior all the way 

up until one hour before the service is 

to commence. TVA argues that no 

service that could preempt the hourly 

service should be sold after the 10 a.m. 

day-ahead deadline, and requests that 

the Commission clarify this ambiguity. 

1198. If the Commission requires 

hourly firm service, Progress Energy 

requests that it be offered on a dayahead basis only, as proposed in the 

NOPR, to allow transmission providers 

sufficient time to analyze the reliability 

impacts of the requested hourly firm 

service. Nevada Companies recommend 

that any hourly firm service have the 

same scheduling deadlines as daily firm 

and that customers not be permitted to 

submit hourly firm schedules 

throughout the day. In Nevada 

Companies’ view, this would enable 

transmission customers to schedule firm 

transmission only for the part of the day 

that it is needed while, at the same time, 

transmission providers would not be 

overwhelmed with the task of 

administering the reservation process. 

1199. Some recommend that 

scheduling conform to the existing 

scheduling practices in each region, 

such as in the WECC.730 For its part, 

MISO argues that the proposed 

scheduling deadline for hourly firm 

service is before the deadline for the 

submittal of the MISO daily firm 

service, which would require a 

substantial change to its Energy Markets 

Tariff, firm service evaluation process, 

and other firm and non-firm timing 

requirements. MISO argues that this 

could adversely affect the current Joint 

and Common Market Alignment of 

Business Practices initiative with PJM. 

Public Power Council offers 


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731E.g., PGP, PNM–TNMP, and WAPA. 

Bonneville’s scheduling timeline as an 

example in which longer blocks get 

priority over the shorter blocks within 

the 10 a.m. to 2 p.m. preschedule-day 

reservation period, and hourly firm is 

bought within the day at the same times 

as hourly non-firm transmission (i.e., up 

to 20 minutes prior to the delivery 

hour). 

1200. Occidental requests that the 

Commission change the 10 a.m. daybefore scheduling timeline to be as close 

to real-time as possible. It contends that 

under the pro forma OATT, merchant 

generators still will be relegated to 

making non-firm reservations and sales, 

because the 10 a.m. prior day firm 

service scheduling timeline would 

cause them to incur expensive 

reservations to the sales point, but not 

be able to have the transaction tagged 

with source and sink (as required under 

the NERC tagging procedure), before 

consummation of the firm hourly 

transaction. Occidental further contends 

that the change in scheduling timeline 

will not be problematic to the 

transmission providers, particularly if 

the transaction takes place in a single 

control area. Occidental also argues that 

the OATT benefits the transmission 

provider, which can favor its own or 

affiliated generation when balancing 

with other control areas and dispatching 

in real time. 

1201. Bonneville, which has provided 

hourly firm service since 2002, takes 

issue with the fact that the Commission 

proposes that the service would become 

unconditional only one hour before the 

commencement of delivery. Bonneville 

argues that its own timeline, under 

which hourly firm service becomes 

unconditional at the close of the 

preschedule window for the day of 

delivery (currently, at 2 p.m. of the 

preschedule day or as soon as 

practicable thereafter), is superior and 

should be adopted by the Commission. 

Bonneville explains that, in its 

experience, customers place great value 

on having unconditional firm rights 

before they reach the real-time 

scheduling window, and an hour leaves 

little or no time to make alternative 

arrangements if the hourly firm 

reservation is preempted. Finally, 

Bonneville foresees potential reliability 

effects if a customer using hourly firm 

transmission for operating reserves is 

preempted the hour before delivery, and 

is unable to make transmission 

arrangements elsewhere. 

1202. Ameren argues that a later 

request for hourly firm service should 

not be able to preempt an earlier 

request, even if it is for a greater number 

of hours. According to Ameren, this will 

provide certainty to users of this service 

since they will know they will not be 

bumped by other customers using the 

service. 

1203. Duke requests guidance on how 

long the hourly firm customer has to 

respond to a competing request. Since 

hourly firm could be preempted up to 

an hour before the schedule starts, Duke 

argues that in many cases there will not 

be 24 hours available and the 

scheduling deadline (of 10 a.m. of the 

day prior to commencement of such 

service) may have passed. For example, 

if a pre-confirmed, longer-term, 

competing request is received just prior 

to the deadline (one-hour prior to 

service commencing), Duke questions 

whether the transmission provider is 

required to offer the right of first refusal 

at all. 

1204. Joined by TranServ, Duke also 

requests that the Commission provide 

guidance on how to administer the right 

of first refusal when, for example, three 

different hourly customers have 

confirmed reservations on a constrained 

interface for different hours in a day and 

the transmission provider then receives 

a pre-confirmed request for daily service 

on the same path for the same day. 

Alternatives solutions for this scenario 

offered by Duke include offering the 

shorter-term customers simultaneous or 

consecutive opportunities to exercise 

the right of first refusal, prohibiting the 

preemption of multiple overlapping 

requests, or denying shorter term 

customers a right of first refusal. Duke 

recommends NAESB develop 

appropriate business practice standards 

after the Commission’s decision on this 

issue. 

1205. With the NOPR’s potential for 

adding more complexity with hourly 

firm service under similar conditions as 

other short-term firm services, TranServ 

requests that the Commission either 

eliminate the conditional nature of 

short-term firm point-to-point service 

under the OATT (and the reservation 

window would be set to not interfere 

with requests for daily firm service) or 

allow hourly firm service to be 

preempted without a right of first 

refusal. 

1206. Duke requests that, whether or 

not the Commission requires hourly 

firm service, the Commission clarify 

how the ‘‘short-term rights of first 

refusal’’ should be implemented in 

section 13.2(iii) of the OATT, since 

there already is some lack of clarity with 

regard to this right for daily, weekly, 

and monthly service. 

1207. Based on its experience, WAPA 

suggests that the Commission institute 

limits on the allowable time period in 

which customers may contact the 

transmission provider for the purpose of 

withdrawing an hourly firm request in 

order to avoid potential ‘‘gaming’’ issues 

that may arise from entities requesting 

transmission on a pre-scheduled basis 

and then asking for the request to be 

withdrawn during real-time. To simplify 

real-time administration of hourly firm 

service, WAPA suggests that the 

Commission explicitly include in the 

revised pro forma OATT a statement 

waiving the Order No. 638 displacement 

rules for hourly requests during the 

hour before the service is to commence. 

1208. Several commenters support the 

Commission’s batching proposal.731

WAPA argues that the proposed 

limitation on batching hourly firm 

requests and schedules to within the 

same day would alleviate the workload 

issues associated with evaluating 

individual hourly firm reservations in 

order to identify conflicting schedules 

across congested paths. 

1209. MidAmerican objects to the 

batching proposal, arguing that 

transmission requests should be 

evaluated in queue order and schedules 

linked to a specific OASIS request. 

MISO argues that the batching proposal 

may interfere with the established 

protocols for transmission service 

request processing. In MISO, for 

example, there is no interface for 

Available Share of Total Flowgate 

Capability, which would seem to 

suggest that batch processing could 

infringe on the various Commissionapproved seams agreements. 

1210. Some commenters offer 

modifications or request clarifications. 

Bonneville proposes that NAESB 

develop industry standards for defining 

and processing batched reservations and 

schedules. EEI argues that transmission 

providers who offer hourly firm service 

should permit their customers to batch 

multiple requests for service that have 

the same points of receipt and delivery; 

are for the same quantity of service, and 

are for the same day. Otherwise, EEI 

explains, batching will complicate the 

ability of the transmission provider to 

study requests for hourly service. 

NorthWestern explains that it cannot 

fully support the Commission’s 

recommendation to allow ‘‘batching’’ of 

requests without a more clear definition 

of what may be batched and a 

determination that requests of a longer 

increment preempt shorter increment 

requests (e.g., a request for daily service 

preempts a request for hourly service) 

regardless of how many hours are 

batched together. 

1211. TranServ states support for the 

ability to batch requests and schedules 

for multiple hours of firm service with 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12421 

732Order No. 888 at 31,665 n.176. 

733 Id. at 31,694. 

734E.g., Southwest Power Pool, Inc., 109 FERC ¶

61,041 at P 6 (2004). 

735 Id. at P 9. 

736 Id. 

737 Idaho Power Co. v. FERC, 312 F.3d 454, 462 

(D.C. Cir. 2002). 

varying capacity over the hours. 

However, with respect to competing 

requests and the right of first refusal, 

TranServ suggests that the preempting 

request must be for a fixed capacity over 

the term of the request to be considered 

a competing request. According to 

TranServ, this would prevent potential 

gaming by a customer submitting a 

request for one extra hour at 1 MW to 

gain priority over another reservation. 

Commission Determination 

1212. In light of the potential for 

market disruption and the scheduling 

complications that would arise from 

providing hourly firm service, we 

decline to adopt in the Final Rule the 

proposal to require transmission 

providers to offer hourly firm service. 

While there is some industry support for 

hourly firm service, we conclude that 

the downsides associated with requiring 

transmission providers to offer hourly 

firm service outweigh the benefits of the 

proposal due to the significant issues 

raised by commenters. Commenters 

opposing mandatory hourly service 

raise a number of legitimate concerns 

with respect to the service’s potential to 

adversely affect reliability and create 

additional complexity and inefficiency 

in scheduling and administering the 

right of first refusal. We do not believe 

that the modifications suggested by 

commenters supporting the service 

adequately resolve these concerns. 

Given regional differences and varying 

system constraints, a solution that may 

be appropriate for resolving scheduling, 

reservation or other issues resulting 

from hourly firm service on one 

transmission system may not be 

appropriate for another transmission 

system. Moreover, even the commenters 

supporting the proposal do not 

demonstrate a clear need for an hourly 

firm service product. The Commission 

therefore concludes that requiring 

hourly firm service is not needed to 

address undue discrimination, the goal 

of this rulemaking. 

1213. To the extent they deem it 

appropriate, transmission providers will 

continue to have the option to propose 

offering hourly firm service in an FPA 

section 205 filing with the Commission. 

Because we are not adopting the 

mandatory hourly firm service proposal, 

we believe that the most serious 

concerns regarding scheduling shortterm service and administering the right 

of first refusal are alleviated. We address 

scheduling and right of first refusal 

issues relating to existing services in 

section V.D.5.b. 

3. Rollover Rights 

1214. Section 2.2 of the pro forma 

OATT allows existing firm transmission 

service customers—wholesale 

requirements and transmission-only 

customers with contracts of one year or 

more—the right to continue to take 

transmission service from the 

transmission provider when the 

customer’s contract expires. The pro 

forma OATT provides that the 

transmission reservation priority is 

independent of whether the existing 

customer continues to purchase 

capacity and energy from the 

transmission provider or elects to 

purchase capacity from another 

supplier. This transmission reservation 

priority for existing firm transmission 

service customers, which is also referred 

to as a right of first refusal or a rollover 

right, is an ongoing right that currently 

may be exercised at the end of all firm 

contract terms of one year or longer. A 

transmission customer must give notice 

of whether it will exercise its right of 

first refusal 60 days before the 

expiration of its service agreement. 

1215. In Order No. 888, the 

Commission provided that, if a 

transmission customer subject to the 

rollover right selects a new power 

supplier that substantially changes the 

location or direction of its power flows, 

the customer’s right to continue taking 

service from the transmission provider 

may be affected by transmission 

constraints associated with the 

change.732 The Commission also 

provided that a transmission provider 

may reserve existing capacity for retail 

native load and network load growth 

reasonably forecasted within the 

transmission provider’s current 

planning horizon, but that any capacity 

so reserved must be posted on the 

transmission provider’s OASIS and 

made available to others until the 

capacity is needed for the anticipated 

network or retail native load use.733 The 

Commission also has held that a 

transmission provider may restrict a 

right of first refusal based on preexisting contracts that commence in the 

future if the transmission provider 

knows at the time of the execution of 

the original service agreement that ATC 

used to serve a customer will be 

available for only a particular time 

period, after which time it is already 

committed to another transmission 

customer under a previously confirmed 

transmission request.734 Once a 

transmission provider evaluates the 

impact on its system of serving a longterm firm transmission customer and 

grants the transmission customer 

existing capacity, the transmission 

provider must plan and operate its 

system with the expectation that it will 

continue to provide service to the 

transmission customer should the 

transmission customer exercise the right 

of first refusal. If constraints arise after 

a transmission provider enters into a 

long-term agreement with the 

transmission customer (and that 

agreement does not contain an allowed 

restriction on the transmission 

customer’s right of first refusal), the 

obligation is on the transmission 

provider to either curtail service to all 

affected customers or build more 

capacity to relieve the constraint.735 A 

transmission provider is obligated to 

curtail service pursuant to its OATT or 

expand its system when its system 

becomes constrained such that it cannot 

satisfy existing transmission customers, 

including the exercise of their rollover 

rights, because it should have planned 

and operated its system with the 

expectation that each long-term firm 

transmission customer will exercise its 

rollover rights.736

1216. If a transmission provider’s 

transmission system cannot 

accommodate all of the requests for 

transmission service at the end of the 

contract term, the existing long-term 

transmission customer must agree to 

match the rate offered by the potential 

customer, up to the transmission 

provider’s maximum rate, and to accept 

a contract term at least as long as that 

offered by the potential customer. 

However, a competitor’s offer does not 

have to be ‘‘substantially similar in all 

respects’’ to the existing transmission 

customer’s.737

NOPR Proposal 

1217. In the NOPR, the Commission 

proposed to revise the right of first 

refusal provision in the pro forma 

OATT to apply to firm wholesale 

requirements and transmission-only 

contracts that have a minimum term of 

five years, rather than the current 

minimum term of one year. In addition, 

a transmission customer under a 

rollover agreement would be required to 

provide notice of whether it intended to 

exercise its right of first refusal no less 

than one year prior to the expiration of 

its contract, rather than the current 60 

days. The Commission proposed to 

maintain the requirement that an 


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12422 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

738E.g., APPA, Barrick Reply, Bonneville, 

Community Power Alliance, Constellation, 

Dominion, Duke, EEI, Entegra, Entergy, E.ON, 

FirstEnergy, Great Northern, Imperial, Indianapolis 

Power Reply, LPPC, LDWP, MidAmerican, MISO, 

MISO Transmission Owners, Nevada Commission, 

Nevada Companies, North Carolina Commission 

Reply, Northwest IOUs, NorthWestern, NPPD, PGP, 

Pinnacle, PNM–TNMP, Progress Energy, Public 

Power Council, Sacramento, Salt River, Santa Clara, 

Seattle, South Carolina E&G, Southern, SPP, 

Tacoma, TAPS, TransServ, TVA, Utah Municipals, 

and Xcel. The Commission notes that several of 

these commenters have conditioned or qualified 

their support on the adoption of a number of 

modifications, which will be discussed below. 

739See also TDU Systems Reply. 

740See also NCEMC and Arkansas Municipal 

(opposing the increase in the minimum term to five 

years). 

existing transmission customer match 

competing offers as to term and rate. 

The Commission discussed whether 

native load restrictions should be 

reevaluated with each rollover and, if 

so, whether native load should then be 

required to compete with rollover 

customers for the capacity. The 

Commission also asked for comment on 

whether there is a sufficiently clear, 

consistent, and transparent method that 

could be implemented on a generic 

basis to address the need for a 

transmission provider to demonstrate its 

forecast of native load growth and its 

effect on capacity reserved by rollover 

customers. The rollover reforms were 

proposed to be effective as to new 

transmission contracts upon 

Commission acceptance of the 

transmission provider’s coordinated and 

regional planning process required by 

the Final Rule, with existing rollover 

contracts becoming subject to the new 

rules on the first rollover date after the 

effective date of the revisions. 

a. Five-Year Minimum Contract Term 

Comments 

1218. Many commenters support the 

increase in the contract term eligible for 

a rollover right.738 These commenters 

support the increase to five years based 

largely on the Commission’s rationale 

for proposing it, i.e., an increase to five 

years would encourage longer-term use 

of the grid and assist in long-term 

planning. Many also point out that a 

longer minimum term reduces the 

universe of contracts transmission 

providers must assume will exist in 

perpetuity, thereby increasing certainty 

and reducing speculation. These 

commenters also argue that rollover 

reform will improve reliability and 

provide increased revenues to perform 

upgrades. Some also argue that this is 

consistent with the native load 

protections in new section 217 of the 

FPA. 

1219. E.ON, for example, notes that 

system expansions may have been 

limited in the past because transmission 

providers did not want to commit 

resources to accommodate a service 

guaranteed for only one year, and Xcel 

and TVA note that the increase in term 

should encourage investment and 

expansion of the grid by providing 

improved certainty of cost recovery. EEI 

stresses that there is no single minimum 

rollover term that works for all parties, 

as power purchase contract terms vary 

and some state planning obligations 

require purchases for longer or fewer 

than five years, but that five years 

represents a reasonable balance. 

Southern emphasizes that the reforms 

should also improve reliability, promote 

the provision of service to native load 

transmission customers, and increase 

market efficiencies by releasing 

transmission capacity to the market. In 

its reply, Southern expresses its belief 

that the current policy of requiring 

transmission planners to assume that all 

agreements having a minimum term of 

one year will continue taking service in 

perpetuity threatens reliability. In 

Southern’s view, this policy results in 

planning that is based on speculation 

and guesswork that can signal a need for 

inappropriate and expensive 

transmission upgrades and mask the 

need for appropriate expansion. 

1220. However, several modifications 

and clarifications were sought by some 

commenters before they could agree to 

an increase in the minimum term to five 

years. APPA, Sacramento, and TAPS 

contend that transmission customers 

making this long-term commitment 

should be permitted to change their 

designated resources and receipt points 

as their power supply needs change.739

APPA also asserts that transmission 

customers that agree to a five-year 

contract term should not be forced to 

compete with other transmission 

customers for firm capacity whenever 

their contracts come up for renewal. 

Without such assurances of continued 

service, APPA argues that the 

Commission’s proposals would not 

comport with section 217 of the FPA.740

1221. In order to further ensure 

continued service, TAPS seeks the 

following modifications: Transmission 

providers should be required to 

redispatch if necessary to accept a 

‘‘reasonably foreseeable’’ and timely 

designated network resource with costs 

shared on a load ratio basis; 

transmission providers should be 

required to offer cost-based sales to 

embedded transmission-dependent 

utilities that cannot reach alternative 

suppliers; and exceptions should be 

permitted to the five-year minimum 

term and matching exposure for small 

embedded transmission-dependent 

utilities and full or near-full 

requirements customers to ensure a 

continued right to service. Additionally, 

TAPS asserts that the minimum rollover 

in the absence of a competing request 

should be one year, rather than five. 

1222. TDU Systems, which generally 

opposes the increase to five years, 

believes that the Commission should 

clarify that rollover customers retain 

their rights to transmission capacity in 

the event of competing bids from either 

the transmission provider or another 

transmission customer if the rollover 

customer matches up to a five-year 

contract term. Lastly, Seattle is 

concerned that with a five-year 

minimum, the risk in multi-segmented 

transmission transactions of one 

segment being undone by refusal of 

another is increased. Seattle suggests 

that acceptance and confirmation of one 

segment be made contingent on 

coordinated acceptance and 

confirmation on all other required 

segments. 

1223. In its reply to the arguments 

that rollover rights should be extended 

to accommodate service at new receipt 

or delivery points, EEI argues that this 

would allow a rollover customer to have 

priority over higher-queued customers 

on transmission paths other than the 

path over which the rollover customer 

is currently taking service, even if the 

new service would have different 

impacts on the transmission system. EEI 

argues that such service would be new 

service and not a rollover of existing 

service. EEI also urges the Commission 

to reject TAPS’s assertion that it should 

require the transmission provider to 

accept rollover customers’ designations 

of any network resources that are 

reasonably foreseeable and to redispatch 

its system if necessary to accommodate 

that resource, because among other 

things this would require providers to 

build the transmission system with 

sufficient redundancy to permit any 

customer to take service from any 

resource. Moreover, EEI argues that 

TAPS does not provide any suggestion 

as to what should be considered a 

reasonably foreseeable resource and that 

sharing costs on a load ratio basis would 

result in eighty to ninety percent of the 

redispatch costs being borne by the 

transmission provider’s native load 

customers. 

1224. EEI also argues in its reply that 

TAPS’s proposal to exempt all small 

customers from the five-year minimum 

term would interfere with transmission 

providers’ ability to plan their systems 

to meet their customers’ needs, as the 


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741 In their replies, Entergy, MidAmerican, and 

Progress Energy note many of these same concerns. 

742E.g., Alberta Intervenors, Alcoa, Ameren, 

AMP-Ohio, Arkansas Municipal, AWEA, Dynegy 

Reply, Eastern North Carolina, EPSA, Exelon, 

Fayetteville, Manitoba Hydro, Morgan Stanley, 

NCEMC, NRECA, MISO/PJM States, PJM, Powerex, 

PPM, Reliant, TDU Systems, TransAlta, Williams, 

and Wisconsin Electric. 

743E.g., Alcoa, AMP-Ohio, Arkansas Municipal, 

AWEA, Eastern North Carolina, EPSA, Exelon, 

Fayetteville, Manitoba Hydro, NCEMC, NRECA, 

MISO/PJM States, Reliant, TDU Systems, and 

Wisconsin Electric. TAPS also notes the difficulties, 

particularly for small transmission-dependent 

utilities, of locking in a five-year supply contract a 

year in advance of rollover. 

744E.g., EPSA, Exelon, Reliant, and MISO/PJM 

States. 

745E.g., EEI Reply and Southern Reply. 

746 e.g., Morgan Stanley and Manitoba Hydro. 

747 e.g., Alberta Intervenors, TransAlta, and 

Williams. 

aggregated loads of several small 

customers can have a substantial impact 

on the system. EEI contends that TAPS’s 

proposal to exempt all full and near-full 

requirements customers is also 

unreasonable, as the transmission 

provider would be forced to provide 

preferential service to certain groups of 

customers. As for the proposal to allow 

customers to exercise rollover rights 

with only one-year contracts if there is 

no competing request, EEI contends 

there is no need for a rollover if there 

is no competing request, since there is 

enough capacity for all and the 

transmission provider will grant the 

customer’s new request for service for 

one year.741

1225. The increase in the minimum 

contract term eligible for a rollover right 

was opposed outright by several 

commenters for a variety of reasons.742

Many of these commenters oppose the 

increase to five years because they claim 

it is difficult under current market 

conditions to secure a five-year power 

supply agreement to underpin a fiveyear transmission contract, particularly 

in organized markets where the focus is 

on spot transactions or where the grid 

is very weak.743 They also argue that 

changes in the market (e.g., fuel costs) 

could significantly change the options 

available to customers within a five-year 

period and that a service extension of 

less than five years may be needed to 

manage delays in generation 

construction or some other 

unforeseeable event. TDU Systems urge 

the Commission to require any 

transmission provider seeking an 

increase in the minimum contract term 

to demonstrate that sufficient economic 

power supplies are available under 

longer-term contracts. EEI replies that 

such an approach would be inconsistent 

with the separation of functions 

between generation and transmission. 

1226. Some commenters also argue 

that five years is incompatible with 

retail procurement processes in some 

states, such as Illinois and New Jersey, 

which they assert limit power supply 

agreements to three years.744 AWEA and 

PPM suggest that the Commission 

increase the minimum term to three 

years, because five years is beyond the 

term for many shorter-term power sales 

transactions and it would be cost 

prohibitive to lock up service for five 

years. Manitoba Hydro suggests a twoto three-year minimum term and that 

guaranteed redirects be permitted. 

Constellation, while generally 

supportive of a five-year minimum term, 

would prefer a three-year minimum 

term because it says three years is more 

closely aligned with much of the 

commercial activity in the energy 

commodity markets. Wisconsin Electric 

supports the current one-year term, but 

proposes three years as an alternative. In 

its reply, Duke indicates that it would 

support a three-year minimum term for 

rollover, but only if the notice period is 

required to match project lead time. 

1227. In their replies, several 

commenters dispute the assertion that 

customers may not be able to obtain 

generation supplies for five-year 

periods. They contend that generators in 

a competitive market will have to offer 

five-year contracts or risk losing their 

sales if LSEs begin requesting five-year 

contract terms in order to obtain 

rollover rights.745 SPP states on reply 

that it has not been its experience that 

suppliers have refused to enter into 

power supply agreements in excess of 

three years. EEI also argues that, even if 

a transmission customer has to accept 

the risk that its term of service exceeds 

the term of its power purchase in order 

to obtain rollover rights, the cost of the 

transmission service that is at risk is 

small in comparison to the cost of the 

power because the cost of transmission 

service is only a small portion of the 

delivered price of energy. EEI and 

Bonneville also note in their replies that 

unneeded transmission service can be 

sold in the secondary market. 

1228. NCEMC opposes the increase in 

contract term because it would inhibit 

the ability to pursue its prudent 

portfolio approach to mitigate price 

risks by providing for a mix of shorter 

and longer-term power supply contracts. 

If the Commission increases the 

minimum term, NCEMC argues that all 

existing rollover contracts should be 

grandfathered. EPSA also believes that 

existing one-year contracts should be 

grandfathered, otherwise it argues that 

market participants that relied on the 

current policy will be harmed. In its 

reply, EEI urges the Commission to 

reject EPSA’s proposal that all currently 

effective one-year power supply 

contracts be grandfathered because, in 

EEI’s view, it would interfere with good 

utility planning. EEI also argues that 

extending the minimum term to five 

years does not abrogate a customer’s 

power supply contract because 

transmission and supply are unbundled 

and, therefore, changing the terms of 

transmission service does not interfere 

with contract rights under power sales 

agreements. 

1229. Exelon argues that limiting 

rollover rights to contracts that are five 

years or greater will discriminate against 

merchant generators that do not have 

load linked to generation, lead to 

stranded generation investments that 

were based on the current rules, and 

unfairly advantage local utilities 

wanting to build their own generation as 

opposed to seeking competitive 

alternatives. Exelon suggests that an 

approach similar to that utilized in PJM 

be adopted, in which PJM evaluates new 

requests for service that cannot be 

granted without utilizing an existing 

customer’s service by notifying the 

existing customer and requiring it to 

match the new request within thirty 

days or release the service. PJM explains 

further that its approach would allow 

transmission customers two rollover 

options: long-term service for less than 

five years with no rollover right, or 

service for one year with indefinite 

rollover rights conditioned on either 

future limitations or an agreement to 

pay for necessary upgrades to maintain 

the rollover. In its reply, TAPS opposes 

the PJM approach stating that it would 

invite discrimination by transmission 

owners. 

1230. Other commenters that oppose 

the increase to five years assert that they 

are already long-term customers that 

simply take service year-to-year and 

should therefore already be included in 

planning, based on the fact that they are 

either a generator or load and cannot 

simply pick up and leave the system.746

Several other commenters likewise 

oppose the increase to five years 

because they do not believe that it will 

result in an increase in long-term 

contracting and planning as suggested 

by the Commission.747 For example, 

Williams notes that it currently has a 

ten-year transmission contract and 

argues that its transmission provider has 

done nothing to improve the grid in its 

area. TransAlta believes that a five-year 

minimum contract term will limit 

market participation to deep-pocketed 

market participants who can afford long 


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748See also Morgan Stanley. 

749See EPAct 2005 sec. 1233(a) (to be codified at 

section 217(b)(4) of the FPA, 16 U.S.C. 824q), which 

provides that ‘‘[t]he Commission shall exercise the 

authority of the Commission under [the FPA] in a 

manner that facilitates the planning and expansion 

of transmission facilities to meet the reasonable 

needs of load-serving entities to satisfy the service 

obligations of the load-serving entities, and enables 

load-serving entities to secure firm transmission 

rights (or equivalent tradable or financial rights) on 

a long term basis for long term power supply 

arrangements made, or planned, to meet such 

needs.’’

750We agree with EEI that requiring transmission 

providers to ensure rollover customers the ability to 

change their designated resources and receipt 

points without disrupting service to other 

customers would, taken to its logical conclusion, 

require transmission providers to construct the 

transmission system with sufficient redundancy to 

permit any customer to take service from any 

resource. 

contracts. TransAlta also believes that 

the current option to contract for just 

one year and obtain a rollover right is 

often the benefit that prompts market 

participants to buy yearly service 

instead of shorter-term products and, 

therefore, is an incentive to purchase 

longer-term service. Alberta Intervenors 

believe that a longer minimum term will 

provide a disincentive for long-term 

trading since the increased time 

commitment of five years will 

significantly increase the trading party’s 

risk.748 The Organizations of MISO and 

PJM States believe that the current 

rollover policy generally results in an 

increase in investment in transmission 

and is only detrimental if service is 

terminated and the capacity goes 

unused. 

Commission Determination 

1231. The Commission finds that the 

current rollover policy is no longer just, 

reasonable, and not unduly 

discriminatory. The rights and 

obligations of a rollover customer 

should bear a rational relationship to 

the planning and construction 

obligations imposed on the transmission 

provider by the rollover rights. We find, 

for the reasons explained below, that the 

current policy no longer meets this 

standard and that a five-year term will 

ensure greater consistency between the 

rights and obligations of customers and 

the corresponding planning and 

construction obligations of transmission 

providers. We also believe that an 

increase to a five-year term is consistent 

with the native load protections 

contained in new section 217 of the 

FPA, primarily because requiring 

longer-term agreements ensures that the 

rollover right is used by transmission 

customers with long-term obligations to 

purchase capacity.749 Accordingly, the 

Commission adopts a five-year 

minimum contract term in order for a 

customer to be eligible for a rollover 

right. At the end of its initial five-year 

contract term, a transmission customer 

must, within the one-year notice period 

(discussed more fully below), agree to 

another five-year contract term or match 

any longer-term competing request in 

order to be eligible for a subsequent 

rollover. 

1232. Our decision to adopt a fiveyear minimum term will remedy many 

of the problems associated with the 

current policy. Under our current 

policy, a customer can secure 

transmission service for one year and, in 

so doing, require the transmission 

provider to plan and upgrade its system 

on the assumption the rollover right will 

be continually renewed. For example, if 

a transmission provider’s planning 

horizon is 10 years, a one-year 

reservation would require the 

transmission provider to plan and 

upgrade the system as if the customer 

had purchased 10 years’ service (i.e., 

would exercise its rollover right every 

year during that 10-year period). 

Because of this, the customer receives a 

guarantee of service beyond what it has 

contracted to pay for and the 

transmission provider must plan for 

service that may not actually be used. 

1233. By failing to link the customer’s 

rights and obligations with those of the 

transmission provider, the current 

policy can have several detrimental 

effects. For example, it requires the 

transmission provider to plan and 

construct facilities that may not be 

necessary to serve load. Given the 

difficulty of siting new transmission, it 

is inappropriate to require transmission 

providers to use finite resources to 

finance and construct facilities that may 

not be necessary. Additionally, the 

current policy harms OATT customers 

by allowing rollover customers to tie up 

capacity that may be needed by other 

customers. This is because the current 

policy allows a rollover customer to 

lock up existing capacity, regardless of 

whether the rollover customer intends 

to use that capacity. This reduces the 

availability of existing capacity for other 

customers and, in turn, reduces 

competitive alternatives for customers. 

1234. Some commenters have argued 

that the Commission should use a 

shorter period, such as three years, that 

is more aligned with auctions in retail 

access markets or existing commercial 

practices. We disagree. The purpose of 

our reform of the rollover rights policy 

is to ensure that the rights and 

obligations of the customer are better 

aligned with the planning and 

construction obligations of the 

transmission provider. It is not to link 

the term of the rollover right to any 

particular commercial practice in any 

particular region. We do not believe that 

such a policy could be fairly 

implemented in any event. Commercial 

practices vary between the regions and 

change over time, and it would therefore 

be impractical to tailor the rollover 

rights in the OATT to the varying 

commercial practices across the 

country. 

1235. We also do not believe that 

adopting a five-year minimum term will 

have an adverse effect on participation 

in retail auctions that use three-year 

solicitations. At the outset, we note that 

retail auctions use solicitations of 

varying length and, hence, the fact that 

some states may use three-year auctions 

does not provide a basis to establish a 

generic standard for rollover rights 

under the OATT. Some states use 

shorter term auctions (e.g., one year) 

and, as indicated, we cannot reasonably 

tailor an OATT rollover obligation to the 

varying commercial practices across the 

country. We also do not believe that our 

policy will have an adverse effect on 

any such auctions. The winners in a 

retail solicitation are determined anew 

in each auction, based on the bids 

submitted in that auction. A prospective 

bidder therefore does not need a 

‘‘rollover right’’ to compete in an 

auction. It only needs transmission 

service over the term of the solicitation 

(e.g., three years). The fact that it may 

not have an automatic right to 

transmission capacity in the next 

auction simply places it on the same 

footing as any other bidder. 

1236. In response to those 

commenters who argue that 

transmission customers making this 

long-term commitment must also be 

permitted to change their designated 

resources and receipt points as their 

power supply needs change, we believe 

that such an approach is unworkable. 

Allowing rollover customers to change 

their designated resources and receipt 

points in this manner would 

inappropriately result in rollover 

customers having priority over other 

transmission customers in the queue 

that may have already requested service 

over a given transmission path. This 

could result in substantial disruptions 

to transmission service to higher-queued 

customers requesting long-term service 

over these paths.750 Moreover, 

transmission customers are not 

currently guaranteed the ability to turn 

to other suppliers at other designated 

resources and receipt points and, 

therefore, we do not understand how 

simply increasing the minimum 

contract term to five years should 


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751E.g., Ameren, Barrick Reply, Bonneville, 

Community Power Alliance, Constellation, 

Dominion, Duke, East Texas Cooperatives, EEI, 

E.ON, Entegra, Entergy, FirstEnergy, Great 

Northern, Imperial, LDWP, LPPC, MidAmerican, 

MISO, MISO Transmission Owners, Nevada 

Commission, Nevada Companies, North Carolina 

Commission Reply, NorthWestern, Northwest IOUs, 

NRECA, PGP, Pinnacle, PNM–TNMP, Progress 

Energy, Public Power Council, Salt River, Santa 

Clara, Southern, South Carolina E&G, SPP, Tacoma, 

TranServ, TVA, Utah Municipals, and Xcel. Both 

APPA and TAPS support a one-year notice 

provision, but only on the condition that the 

clarifications and modifications they suggest are 

made. 

752E.g., Barrick Reply, Duke, EEI, Entergy, 

Indianapolis Power Reply, LPPC, Nevada 

Commission, Nevada Companies, Pinnacle, 

Progress Energy, South Carolina E&G Reply, 

Southern, and TVA. 

necessarily result in allowing 

transmission customers this increased 

flexibility. Likewise, we do not 

understand why an increase in the 

minimum contract term should result, 

as argued by APPA, TAPS, and others, 

in a transmission customer not having 

to compete with other transmission 

customers for firm capacity whenever 

its contract comes up for renewal. As 

discussed below, we will continue to 

require transmission customers to match 

competing requests for service as to 

term and rate, ensuring that 

transmission customers that value the 

service the most receive it. 

1237. We reject TAPS’ proposal to 

exempt all small customers from the 

five-year minimum, since this would 

interfere with transmission providers’

ability to plan their systems to meet 

their customers’ needs. As EEI points 

out, the aggregated loads of several 

small customers can have a substantial 

impact on the system. We therefore 

believe it would be inappropriate to 

categorically exempt small customers. 

We also reject TAPS’ proposal to 

exempt all full and near-full 

requirements customers, because it 

would force transmission providers to 

provide preferential service to certain 

groups of customers. Additionally, we 

reject TAPS’ proposal to allow 

customers to exercise rollover rights 

with only one-year contracts if there is 

no competing request. Without a 

competing request, a rollover right is not 

necessary in order to continue service as 

long as capacity remains available. 

Additionally, allowing a rollover for a 

one-year contract would continue to 

impose planning and construction 

obligations on the transmission provider 

that bear no reasonable relation to the 

rights and obligations of the rollover 

rights customer. We further reject TDU 

Systems’ proposal that transmission 

providers demonstrate the availability of 

long-term supplies before moving to a 

five-year term. To do so would 

effectively require transmission 

providers to engage in the business of 

procuring supplies for their 

transmission customers, which is 

clearly outside the scope of their 

obligation to provide transmission 

service, and could implicate Standards 

of Conduct issues. 

1238. We also reject the proposal of 

EPSA and others that all currently 

effective one-year power supply 

contracts be grandfathered because this 

would disrupt transmission planning. 

For example, such an approach would 

require that a large portion of existing 

capacity be planned for on a 

significantly different timeline than that 

subject to the reformed rollover right. 

This also would detract from one of the 

primary goals of rollover reform, which 

is to improve transmission planning and 

encourage longer-term contracting. As 

discussed below, existing transmission 

contracts will be permitted to roll over 

under their existing terms until the first 

such rollover opportunity following the 

effectiveness of the reforms required by 

this Final Rule. 

1239. Lastly, we note that many of the 

reforms adopted elsewhere in this Final 

Rule will be beneficial to customers that 

no longer receive rollover rights, as well 

as to customers with rollover rights that 

wish to use their rollover rights to turn 

to alternative suppliers using different 

transmission paths. First, greater 

consistency and transparency in ATC 

calculations will provide greater 

assurance of nondiscriminatory access 

to existing transmission capacity. 

Second, our reforms relating to 

conditional firm and redispatch service 

will help to maximize the use of 

existing capacity, consistent with 

reliability, thereby providing customers 

without rollover rights greater flexibility 

to purchase existing transmission 

capacity. Third, our clarifications 

regarding our policy on redirects should 

improve the ability of transmission 

customers to redirect their service to 

new receipt or delivery points. Fourth, 

lifting the price cap on reassigned 

transmission capacity should assist 

transmission customers in reassigning 

any capacity that may not be needed on 

a given path because of a change in 

suppliers that requires service over new 

transmission paths. This will also 

necessarily result in the unneeded 

capacity being freed up for use by other 

transmission customers, thereby further 

assisting them in obtaining capacity that 

they need to access alternative 

suppliers. Lastly, and most importantly, 

greater openness and coordination in 

transmission planning should provide 

all customers better information 

regarding future resource options and 

access to competitive alternatives. We 

also believe that improved transmission 

planning should help to address 

allegations made by certain 

transmission customers (e.g., Williams) 

that even though they have signed up 

for ten years of service, they have not 

seen their needs planned for adequately. 

b. One-Year Notice Provision 

Comments 

1240. Many commenters support an 

increase in the notice period to one year 

or some other greater time period.751

Most support the increase based on the 

argument that the current 60-day notice 

period makes it very difficult to plan the 

system, because transmission providers 

often do not know until 60 days before 

the end of a contract whether a 

transmission customer will roll over its 

service, resulting in potential 

overbuilding of the system (e.g., because 

a transmission provider must plan its 

system assuming a transmission 

customer will roll over but sometimes it 

does not). They also argue that it is 

difficult to re-market capacity in only 60 

days if rollover is not sought and that 

potential transmission customers are 

often unnecessarily turned away 

because transmission providers are 

unaware of the availability of capacity 

until 60 days before the end of a 

contract subject to a rollover right. In 

general, these commenters view a oneyear notice period as an improvement. 

However, many of these same 

commenters do not believe one-year 

notice is appropriate if the transmission 

provider must construct facilities to 

accommodate a rollover and, therefore, 

the notice should instead be tied to the 

start date for any necessary upgrades.752

1241. EEI, for example, believes that 

notice should be tied to the start date of 

any necessary transmission upgrades, 

because the transmission provider may 

be left with stranded transmission 

capacity if it must begin construction on 

upgrades necessary to accommodate a 

rollover before the transmission 

customer has even indicated whether it 

will in fact seek a rollover. EEI also 

argues that a competing customer could 

be required to pay an incremental rate 

for network upgrades that could have 

been avoided if the rollover customer 

had provided earlier notice of its 

intention not to seek a rollover. EEI 

further contends that some state 

commissions will not allow upgrades 

where there is only the potential for a 

rollover. Finally, EEI states that a oneyear notice period does not ensure that 

the transmission provider will be able to 

re-market the capacity, forcing other 


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753Ameren, Pinnacle, Southern, and TranServ 

agree that the submission of a competing request 

should trigger an accelerated timeline for the 

original customer to exercise or release its rollover 

rights. 

754E.g., Alberta Intervenors, Alcoa, Arkansas 

Municipal, EPSA, Exelon, Manitoba Hydro, Morgan 

Stanley, PPM, TransAlta, Williams, and Wisconsin 

Electric. 

755E.g., Arkansas Municipal, Williams, and 

Wisconsin Electric. 

transmission customers to bear the 

increased costs associated with the 

newly constructed transmission 

facilities. EEI proposes that a date be 

included in the initial service agreement 

by which the transmission customer 

must exercise its rollover rights if 

upgrades are needed to accommodate 

the rollover. If there is a pre-confirmed 

competing request or newly projected 

growth in native load, EEI suggests that 

the rollover customer must exercise its 

rollover and match by the later of the 

project start date for any new 

transmission facilities needed or 60 

days after the transmission provider 

notifies the transmission customer of 

the competing request.753 Additionally, 

if more than one-year notice is required 

because of the need for upgrades, EEI 

proposes that the transmission provider 

be required to notify the transmission 

customer if subsequent events delay the 

project start date, in which case the 

notice period would be revised. EEI 

asserts that any disputes can be dealt 

with by protesting the filing of an 

unexecuted agreement. EEI stresses that 

better, more inclusive planning, and 

more transparent ATC calculations, will 

provide transmission customers with 

greater assurances that project start 

dates are accurate. 

1242. Southern suggests that partial 

rollover be permitted if notice is not 

given in time for construction of an 

upgrade needed to provide full service. 

Duke, Nevada Commission, and 

Southern suggest that providing for oneyear notice without a link to the start 

date for any upgrades falls short of the 

native load protections found in section 

217 of the FPA. As an alternative, the 

Nevada Commission suggests tying the 

notice requirement to the amount of 

capacity subject to rollover, i.e., below 

a certain threshold, one year would be 

deemed per se sufficient. 

1243. APPA argues in reply that many 

customers may not know even one year 

in advance if they will have firm power 

supplies under contract that would 

enable them to roll over their 

corresponding firm transmission 

agreement and, therefore, requiring 

them to exercise their rollover rights 

even earlier in the contract term would 

only exacerbate an already impossible 

situation. In their replies, NRECA, 

TAPS, TDU Systems, and Utah 

Municipals urge the Commission to 

reject the recommendation that notice 

periods be expanded to be 

commensurate with construction lead 

times. They argue, among other things, 

that LSE transmission customers need a 

reasonable amount of certainty so that 

they may plan their power supply 

arrangements without fear that they may 

become unraveled due to unforeseeable 

circumstances. Utah Municipals also 

assert that the proffered justification for 

the proposal—to prevent overbuilding—

is questionable at best as even the 

current policy which requires only a 

one-year contract minimum for rollover 

and 60-days notice has not resulted in 

wasteful overbuilding of the system. 

TDU Systems also point out that under 

section 28.2 of the pro forma OATT, 

transmission providers should be 

planning and expanding their systems 

to accommodate their network 

customers’ current and future needs. 

1244. The one-year notice provision is 

opposed by several commenters, who 

argue that having to give one-year notice 

constitutes an undue burden.754 In 

general, these commenters argue that 

under current market conditions, 

transmission customers do not typically 

renew supply contracts one year in 

advance of expiration.755 Alberta 

Intervenors argue that a one-year notice 

provision does not aid in re-marketing 

capacity, as any unused long-term firm 

service is already re-marketed as shortterm firm or non-firm service. Alberta 

Intervenors also argue that the increased 

lead time increases risk and creates 

uncertainty making it less likely that 

customers will enter into long-term 

contracts. EPSA and Exelon suggest a 

flexible notice rule that depends on the 

length of the underlying contract or 

requiring more than 60-days notice if 

there is insufficient capacity for a new 

long-term firm transmission service 

request, as is done in PJM. They also 

suggest PJM’s approach whereby a 

transmission customer must inform PJM 

whether it will roll over within thirty 

days of being notified of a competing 

request. PPM and Wisconsin Electric 

suggest a six-month notice period, 

which complements their alternative 

suggestion of a three-year minimum 

contract term. 

Commission Determination 

1245. The Commission finds that the 

current 60-day notice period should be 

modified to reflect the longer term (five 

years) of the rollover rights. Currently, 

a customer with a one-year rollover 

right has 60 days to provide notice of 

whether it intends to rollover its 

capacity. This 60-day period was 

reasonable for a rollover right of short 

duration (one year), but it is no longer 

reasonable for a rollover right with a 

minimum five-year term. 

1246. In selecting a new notice 

period, the Commission has attempted 

to balance the circumstances faced by 

customers in renewing power supply 

contracts and the interests of 

transmission providers in attempting to 

plan their system. The Commission 

recognizes that no single notice period 

can perfectly balance these 

considerations, but chooses the one-year 

notice period as most appropriate under 

the circumstances. Given that the 

minimum rollover term has been 

lengthened to five years, it is reasonable 

to expect that customers will consider 

renewing such long term obligations in 

advance of 60 days prior to the 

expiration of their current obligation. 

We do not believe it is reasonable to 

fashion our notice period for customers 

that wait until the last minute to 

evaluate whether to extend their longterm contracts. 

1247. Many transmission providers 

argue that a one-year notice period is 

too short because it is not consistent 

with the transmission provider’s 

planning horizon. We disagree. The 

Commission is extending the minimum 

term for rollover rights to five years to 

ensure greater consistency between the 

customer’s rights and obligations and 

the planning and construction 

obligations of the transmission provider. 

We believe that this modification 

satisfies the principal concerns of 

transmission providers regarding the 

current policy on rollover rights. We 

recognize that a one-year notice period 

is shorter than the typical planning 

horizon, but we decline to extend the 

notice period to a time that coincides 

with the typical planning horizon or the 

time it takes to construct new facilities. 

Doing so would effectively eliminate 

rollover rights altogether, given that the 

resulting notice period could be threeto-five years. We do not believe it is 

reasonable to expect customers to have 

decided on new sources of supply three 

years in advance of the expiration of 

their current contracts. We therefore 

find that a one-year notice period most 

appropriately balances the interests of 

customers and transmission providers. 

c. Matching and Rollover Restrictions 

Based On Native and Network Load 

Growth 

Comments 

1248. As noted above, the 

Commission proposed to maintain the 

requirement that an existing rollover 


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756E.g., MidAmerican and Powerex. 

757E.g., Allegheny, Entergy, FirstEnergy, 

Imperial, Nevada Companies, Progress Energy, Salt 

River, Santa Clara, and Seattle. 

758E.g., AWEA, Duke, EEI, Entergy, EPSA, 

Imperial, Nevada Commission, Powerex, Salt River, 

Seattle, South Carolina E&G, Southern, SPP Reply, 

and TAPS. 

759E.g., AWEA, EEI, EPSA, and MISO. 

760E.g., Nevada Companies, South Carolina E&G, 

and Southern. 

transmission customer match competing 

offers as to term and rate. Some 

commenters argue that a competing 

customer be required to execute a 

contingent service agreement that 

becomes effective if the rollover 

customer does not match.756 Given the 

increase in the minimum contract term 

to five years in order to be eligible for 

a rollover right, TAPS argues that 

matching must be structured to 

recognize that a network customer must 

extend its power supply by at lease five 

years as well, in order to match a 

competing point-to-point customer that 

can simply extend its reservation. To 

ensure that network customers are not 

disadvantaged by matching, TAPS 

suggests that the Commission restrict 

reservations qualified to compete 

against a network customer’s reservation 

to customers with long-term power 

contracts, so they are on more equal 

footing with network customers. TAPS 

also proposes a cut-off for requests with 

which the network customer will need 

to compete, such as three months prior 

to when the network customer exercises 

its rollover right, so that the network 

customer can structure its power supply 

commitments with some degree of 

advance knowledge of the competing 

requests. In its reply, Bonneville 

suggests allowing network transmission 

customers to compete based on the 

duration of their network transmission 

service request rather than on the 

duration of their resource commitments. 

As such, the transmission provider 

would assume that existing designated 

resources would continue to be used 

after the rollover unless informed 

otherwise. 

1249. The Commission also discussed 

in the NOPR whether native load 

restrictions should be reevaluated with 

each rollover and, if so, whether native 

load should then be required to compete 

with rollover customers for the capacity. 

Several commenters argue that a 

transmission provider’s native and 

network loads should not be forced to 

compete with other transmission 

customers, as opposed to allowing the 

transmission provider to continue to 

reserve capacity for its native and 

network load at the time of granting a 

rollover.757 Most also stress that 

requiring a transmission provider to 

compete would violate the native load 

protections in section 217 of the FPA. 

LDWP contends that there should be no 

limitation on a transmission provider’s 

right to recall capacity based on revised 

forecasts of native load growth. 

1250. APPA contends on reply that 

transmission customers could find it 

very difficult to line up a new firm 

power supply of a term long enough to 

match the power supply arrangements 

of its vertically-integrated investorowned transmission provider (which is 

likely to have owned, rate-based 

generation in its power supply portfolio 

and, therefore, could agree to a very 

long-term transmission agreement). TDU 

Systems argue that transmission 

providers should be forced to compete 

for capacity and that this is, in fact, 

required by section 217 of the FPA, as 

the native load preference does not 

distinguish between the retail native 

loads of transmission providers and the 

native loads of other LSEs dependent on 

their systems. Powerex and PPM also 

support requiring transmission 

providers to compete. NorthWestern 

and Southern support requiring 

transmission providers to compete, but 

only when a restriction is not included 

in the original agreement. APPA also 

notes in its reply comments that, if 

Southern included LSEs’ loads in its 

transmission planning and construction 

program along with its own native load, 

there would be no need to reclaim the 

LSEs’ capacity at the close of the initial 

contract term or the renewal terms. 

1251. Several commenters also 

addressed the Commission’s request for 

comment on whether there is a 

sufficiently clear, consistent, and 

transparent method that could be 

implemented on a generic basis to 

address the need for a transmission 

provider to demonstrate its forecast of 

native load growth and its effect on 

capacity reserved by rollover customers. 

Many of these commenters support the 

development of a clear and transparent 

method for demonstrating native load 

growth.758 Some commenters point to 

the need for accurate and transparent 

ATC calculations to aid in this 

process.759 If the transmission 

provider’s calculation of ATC is 

consistent with the requirements the 

Commission adopts in this proceeding 

yet there is insufficient capacity to 

accommodate the customer’s rollover, 

EEI recommends that the provider may 

include in the service agreement a 

limitation of rollover rights. AWEA 

recommends that transmission 

providers adopt the same transparent 

and consistent methods used to 

compute the Existing Transmission 

Capacity component of ATC to develop 

native load growth reservations that 

support rollover restrictions. AWEA, 

NorthWestern, and TAPS suggest 

posting forecast information on the 

OASIS, and TAPS goes on to stress that 

this information should be included in 

state planning documents as well as the 

transmission provider’s coordinated and 

regional planning process. EPSA 

stresses that native load capacity must 

follow native load and not only be made 

available for the transmission provider 

and its affiliates. EPSA believes this is 

required by the native load protections 

found in FPA section 217. 

1252. Duke asks the Commission to 

address the possibility that capacity 

subject to a rollover right might be 

needed to serve native load outside of 

the ten-year planning horizon. The 

Nevada Commission and Southern 

suggest that the Commission give 

deference to state resource planning 

processes in attempting to verify native 

load growth forecasts. Southern also 

asks that the Commission clarify that 

rollover rights can be restricted based on 

rollover rights belonging to higherqueued transmission customers. If 

transmission studies show no problems 

without the presence of a rollover, but 

then problems are identified with the 

rollover included, Southern contends 

that placing a corresponding limitation 

in the service agreement would be 

appropriate. Pinnacle requests 

clarification that when rollover rights 

are restricted based on native load 

growth, the transmission customer must 

pay for upgrades to continue its service. 

1253. Several commenters also 

suggest that transmission providers 

should be permitted to evaluate rollover 

restrictions at the time of each 

rollover.760 These commenters argue 

that it is impossible to identify all 

potential limitations upfront as system 

conditions change in unforeseeable 

ways (e.g., fluctuations in fuel prices 

can change dispatch decisions). They 

also argue that allowing a re-evaluation 

is consistent with the native load 

protections in FPA section 217. 

1254. In its reply, TAPS argues that a 

transmission provider should not be 

permitted to avoid its planning and 

expansion obligations by treating load 

growth not anticipated and documented 

in the original service agreement as a 

competing request to be matched. TAPS 

points out that section 217 of the FPA 

treats all LSEs—whether they are 

transmission providers or transmissiondependent utilities—the same, without 


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761See also APPA Reply and TDU Systems Reply. 

762See Order No. 888–A at 30,197. 

763 Id. 

764 While the Commission has not to date 

accepted any native load growth showing made by 

a transmission provider, it has recently set for 

hearing several such showings. See, e.g., Southern 

Co. Servs., Inc., 116 FERC ¶ 61,050 (2006); Nevada 

Power Co., 116 FERC ¶ 61,093 (2006). 

765We note that this is consistent with the 

Commission’s evaluation of rollover restrictions 

proposed by transmission providers in the past. 

See, e.g., Nevada Power Co., 97 FERC ¶ 61,324 at 

62,493 n.17 (2001). 

766 In its reply, CAISO argues that this request to 

expand the requirements of Order No. 681 is 

inappropriate both because the Commission and 

courts have already recognized that rollover rights 

under the pro forma OATT do not apply to entities 

like CAISO that do not offer traditional Order No. 

888 network and point-to-point transmission 

services and because the Commission has already 

rejected such a requirement in Order No. 681 itself. 

distinction, and therefore provides no 

basis to allow one LSE to claim 

transmission rights currently used by 

another LSE.761 Lastly, TAPS argues 

that when a provider is reclaiming 

capacity for load growth reserved in the 

initial service agreement, rollover 

customers should be allowed to match 

the request, thereby imposing an 

additional requirement on the provider. 

Commission Determination 

1255. The Commission will not adopt 

any changes to its matching policies at 

this time. At the time of rollover of their 

contracts, transmission customers will 

continue to be required to match 

competing requests for service as to 

term and rate in order to roll over their 

service. This preserves the current 

policy goal of providing a mechanism 

for awarding capacity to those who 

value it most, as well as providing for 

a tie-breaking mechanism when needed 

that gives priority to existing customers 

so that they may continue to receive 

transmission service.762 Absent the 

requirement that the customer match 

the contract term of a competing 

request, transmission providers could be 

forced to enter into shorter-term 

arrangements that could be detrimental 

from both an operational standpoint 

(i.e., system planning) and a financial 

standpoint.763 We clarify, however, that 

transmission customers must also enter 

into a transmission contract of at least 

five years in order to obtain a 

subsequent rollover right in the absence 

of a competing request for a longer term. 

1256. The Commission will continue 

to require rollover restrictions based on 

reasonable forecasts of native load 

growth or preexisting contracts that 

commence in the future to be included 

in the initial transmission service 

agreement. This will remain the only 

appropriate way to restrict a rollover 

right. We also will continue to evaluate 

a transmission provider’s native load 

growth forecasts on a case-by-case basis, 

as no commenter has provided us with 

a sufficiently clear, consistent, and 

transparent method that could be 

implemented on a generic basis that 

ensures that the demonstration of native 

load growth is accurate and is tied to a 

need for the specific capacity reserved 

by a rollover customer.764 Because we 

will continue to require rollover 

restrictions to be included in the initial 

transmission service agreement, we 

necessarily reject the suggestion that 

transmission providers be permitted to 

restudy for rollover restrictions at the 

time of each rollover. Accordingly, it is 

unnecessary for us to address whether it 

would be appropriate for a transmission 

provider’s native or network load to 

compete with a rollover customer if a 

new study at the time of the rollover 

indicated a native or network need for 

the capacity. 

1257. In response to the suggestions of 

some commenters, we believe that 

consideration should be given in our 

case-by-case evaluations of native load 

growth forecasts to state-approved 

integrated resource plans that show a 

native load need for the capacity.765

Moreover, we believe that the ATC and 

planning reforms that we are adopting 

in this Final Rule will provide greater 

transparency and assurance that 

transmission providers’ forecasts of 

native load growth are accurate. We 

emphasize that we expect the forecasts 

utilized in transmission planning to be 

consistent with the forecasts utilized to 

support a rollover restriction. Lastly, the 

coordinated and regional planning 

process required by this Final Rule is 

designed to improve the availability of 

transmission service by, among other 

things, increasing transparency and 

providing customers a meaningful 

opportunity to participate in the 

planning process. Accordingly, we 

believe that improved planning should 

help to reduce the need to restrict 

rollovers in the future. 

d. Other Issues 

Comments 

1258. A number of comments relate to 

the applicability of the rollover-related 

reforms to RTOs and ISOs. CAISO asks 

the Commission to confirm that the 

rollover reforms do not apply to CAISO 

as its current tariff does not have such 

a provision and rollover is, in fact, 

incompatible with CAISO’s 

transmission service model. 

Sacramento, however, asks the 

Commission to clarify that rollover 

rights apply to long-term firm service 

provided by RTOs and ISOs under 

Order No. 681 under what it terms the 

‘‘as good as or superior to’’ standard.766

Organization of MISO and PJM States 

assert that any changes for RTOs should 

be made through the stakeholder 

process. In its reply, Williams opposes 

permitting RTO stakeholders to 

determine changes in rollover rights 

policy in RTO regions, as it would result 

in disparate rules and practices and 

increased opportunities for 

discrimination, and therefore, the 

Commission should adopt a single 

policy applicable to all rollover rights. 

1259. Other commenters raise 

different discrete issues. Morgan Stanley 

asks the Commission to amend pro 

forma OATT section 2.2 to include 

existing policy determinations with 

respect to the manner in which a 

transmission provider can curtail or, 

alternatively, must honor and 

accommodate rollover requests. Duke 

asks the Commission to abandon its 

existing policy prohibiting the 

restriction of rollover rights based on 

the potential exercise of other 

customers’ rollover rights. Salt River 

asks the Commission to clarify that the 

proposal to extend the minimum term to 

five years does not change the definition 

in section 1.20 of the pro forma OATT 

that one year constitutes a long-term 

contract. AWEA, Constellation, and 

EPSA ask the Commission to allow 

transmission customers to waive their 

rollover rights. 

Commission Determination 

1260. As we explain in section IV.C 

above, RTOs and ISOs must submit a 

filing showing that their practices are 

consistent with or superior to the 

modifications made in the Final Rule. 

This does not necessarily mean that 

entities such as CAISO must create 

rollover rights if they do not have them 

already. Arguments regarding the 

applicability of rollover reform may be 

raised pursuant to the process described 

in section IV.C. We also clarify that our 

decision to extend the minimum term to 

five years does not change the definition 

in section 1.20 of the pro forma OATT 

that one year constitutes a long-term 

contract. Commenters have not offered 

sufficient justification for further 

clarifications to our rollover policies or 

amendments to section 2.2 at this time. 

e. Effectiveness Upon Acceptance of 

Coordinated and Regional Planning 

Process and Transition 

Comments 

1261. Several transmission customers 

and other commenters support a linkage 


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767E.g., AWEA, Constellation, EPSA, Exelon, 

PGP, and PPM. 

768E.g., Bonneville, Duke, EEI Reply, North 

Carolina Commission Reply, Northwest IOUs, 

PNM–TNMP Reply, Progress Energy, Public Power 

Council, South Carolina E&G Reply, and Southern. 

769E.g., Northwest IOUs, Duke Reply and EEI 

Reply. 

770E.g., APPA, FirstEnergy, Northwest IOUs, PGP, 

and Public Power Council. 

between rollover reform and planning, 

but do not support making rollover 

reforms effective upon acceptance of a 

transmission provider’s coordinated and 

regional planning process, but rather on 

successful implementation of that 

process.767 While both TAPS and TDU 

Systems support the link to planning 

generally, TAPS goes further and 

advocates holding transmission 

providers accountable for failing to plan 

and construct facilities needed to meet 

transmission customer needs. TDU 

Systems point out that the linkage to 

planning does not remedy concerns that 

the current market does not generally 

provide for five-year supply contracts. 

1262. Some commenters, however, 

oppose linking the effectiveness of 

rollover reform to planning, arguing that 

rollover reform is needed as quickly as 

possible.768 For example, Duke, Progress 

Energy, and Southern argue that FPA 

section 217 provides no indication that 

the native and network load protections 

inherent in rollover reform should be 

subject to conditions such as waiting for 

the Commission to accept a planning 

process. Moreover, Duke argues that 

developing a planning process will be 

time-consuming and that holding 

rollover reform hostage to it could 

motivate stakeholders with contracts 

shorter than five years to endlessly try 

to convince the Commission to delay 

acceptance of a transmission provider’s 

planning process. 

1263. Some commenters contend that 

linking planning and rollover reform 

will create differences in tariffs, with 

each transmission provider having a 

different effective date for rollover 

reforms.769 MISO argues in its reply that 

the Commission should clarify in the 

Final Rule that its requirement that the 

new policy becomes effective upon 

acceptance of the transmission 

provider’s coordinated and regional 

planning process is already met in 

regions where RTOs or ISOs provide 

service, as they already have 

Commission-approved regional 

transmission planning mechanisms in 

place. Bonneville argues in its reply for 

a consistent implementation date across 

all transmission providers so as to avoid 

another degree of complexity for 

customers requiring rollover capacity 

across multiple transmission providers’

systems. 

1264. As for the transition period 

proposed in the NOPR, a variety of 

commenters point out that, depending 

on the status of any given contract, 

making the one-year notice provision 

effective on acceptance of a 

transmission provider’s planning 

process could leave some transmission 

customers unable to provide one-year 

notice if there is less than one year 

remaining on their contracts.770

FirstEnergy, Exelon, Great Northern, 

and TAPS emphasize that existing 

transmission customers should be 

permitted one more rollover under the 

current rules, because the parties to 

such agreements have relied on the 

current rules in meeting their 

transmission needs. APPA and TAPS 

point out that transmission customers 

will need a sufficient amount of time to 

secure five-year power agreements to 

meet the new requirements. AWEA 

argues generally for a transition period 

during which existing customers can 

maintain or relinquish their existing 

rollover rights under current rules and 

become subject to new requirements 

only at the end of the transition period. 

Commission Determination 

1265. The Commission adopts the 

NOPR proposal to make rollover reform 

effective at the time of acceptance by the 

Commission of a transmission 

provider’s coordinated and regional 

planning process also required by this 

Final Rule. We believe that rollover 

reform and transmission planning are 

closely related, because according to our 

longstanding policy, transmission 

service eligible for a rollover right must 

be set aside for rollover customers and 

included in transmission planning. We 

believe that it is necessary that reforms 

in both areas proceed together, and 

therefore, we reject the suggestion of 

some commenters that rollover reform 

proceed independent of transmission 

planning reform. We understand that 

our approach may result in differences 

in transmission providers’ OATTs, with 

some having a different effective date 

for rollover reforms. However, because 

the effectiveness of rollover reform will 

be tied to acceptance of a transmission 

provider’s coordinated and regional 

transmission planning process, rollover 

reforms in any given region generally 

should be effective within the same time 

period. 

1266. We reject the arguments by 

some commenters that rollover reform 

be made effective upon the ‘‘successful’’

implementation, as opposed to 

acceptance by the Commission, of a 

transmission provider’s coordinated and 

regional planning process. We believe 

that utilizing a subjective deadline, such 

as the successful implementation of the 

planning process, could result in 

significant confusion in the industry as 

to when rollover reforms should be 

effective. Furthermore, an existing filed 

and accepted transmission planning 

process, such as those that may be on 

file for RTOs and ISOs, does not trigger 

the effectiveness of rollover reform for 

transmission providers using the 

process. Such RTOs and ISOs and their 

transmission-owning members must, as 

discussed elsewhere in this Final Rule, 

comply with the planning reforms 

required by the Final Rule through the 

compliance filing procedures identified 

in section IV.C. It is Commission 

acceptance of these compliance filings 

that will trigger effectiveness of rollover 

reform for these transmission providers, 

assuming rollover reform is applicable 

to their tariff services in the first 

instance. 

1267. In response to commenters’

concerns that, depending on the 

effective date of rollover reform, certain 

customers may not have a year or more 

left on their contracts such that they can 

comply with the one-year notice 

provision, we emphasize that existing 

contracts with a rollover right at the 

time of effectiveness of rollover reform 

may exercise their next rollover based 

on the existing notice rules. It is only a 

rollover contract entered into or 

renewed after the effectiveness of 

rollover reform that must comply with 

the new rollover provisions, including 

the one-year notice requirement. 

4. Modification of Receipt or Delivery 

Points 

1268. Section 22 of the pro forma 

OATT provides that a transmission 

customer taking firm point-to-point 

service may modify its receipt and 

delivery points, i.e., redirect its service, 

on either a non-firm or a firm basis. 

Section 22.1 (Modifications on a NonFirm Basis) provides that, subject to 

certain conditions, a firm point-to-point 

customer may request transmission 

service on a non-firm basis over receipt 

and delivery points other than those 

specified in its service agreement 

(known as secondary receipt and 

delivery points) in amounts not to 

exceed its firm capacity reservation, 

without incurring an additional nonfirm point-to-point service charge or 

executing a new service agreement. 

Section 22.2 (Modifications on a Firm 

Basis) provides that any request to 

modify receipt and delivery points on a 

firm basis shall be treated as a new 

request for service in accordance with 


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771The WEQ was established by NAESB in 

response to a Commission order requesting the 

wholesale electric power industry to develop 

business practice standards and communication 

protocols by establishing a single consensus, 

industry-wide standards organization for the 

wholesale electric industry. See Order No. 676 at 

P 3–4. 

772The standards will hereinafter be referred to 

as the WEQ Standards. The Commission adds a 

reference to the WEQ Standards in section 4 of the 

pro forma OATT, which identifies the 

Commission’s regulations containing the terms and 

conditions relevant to the OASIS and standards of 

conduct. 

773The requirements for dealing with redirects on 

a firm basis are found at WEQ Standard 001–9, et 

seq., and the requirements for dealing with redirects 

on a non-firm basis are found at 001–10, et seq. 

774Order No. 676 at P 52. 

775 Id. at P 53–61. 

776The Commission noted in this regard that the 

WEQ’s procedures ensure that all industry members 

can have input into the development of a business 

practice standard, whether or not they are members 

of NAESB, and each standard it adopts is supported 

by a consensus of the five industry segments: 

transmission, generation, marketers/brokers, 

distribution/load-serving entities, and end-users. 

See Order No. 676 at P 5 & n.5. 

777 E.g., EEI, Imperial, NorthWestern, Southern, 

and Suez Energy NA. 

section 17 of the pro forma OATT 

(Procedures for Arranging Firm Point-toPoint Transmission Service), except that 

the transmission customer shall not be 

obligated to pay any additional deposit 

if the capacity reservation does not 

exceed the amount reserved in the 

existing service agreement. While such 

new request is pending, the 

transmission customer retains its 

priority for service at the existing firm 

receipt and delivery points specified in 

its service agreement. 

1269. In Order No. 676, the 

Commission adopted the ‘‘Standards for 

Business Practices and Communication 

Protocols for Public Utilities’’ developed 

by the NAESB’s Wholesale Electric 

Quadrant (WEQ).771 Order No. 676 

incorporated the aforementioned 

standards by reference into the 

Commission’s regulations, required 

public utilities to implement the 

standards by July 1, 2006, and required 

public utilities to file revisions to their 

OATTs to include these standards.772

The WEQ Standards include a number 

of standards addressing requirements 

for dealing with redirects on both a firm 

and non-firm basis.773 All of the WEQ 

Standards dealing with redirects were 

adopted by the Commission in Order 

No. 676, except for WEQ Standard 001–

9.7, which addresses the impact of a 

firm redirect on a long-term firm 

transmission customer’s rollover rights 

under section 2.2 of the pro forma 

OATT. The Commission directed the 

WEQ to reconsider WEQ Standard 001–

9.7 and to adopt a revised standard 

consistent with the Commission’s 

policies.774 The Commission also 

offered guidance to assist the WEQ in 

developing a standard that is consistent 

with Commission policy.775

NOPR Proposal 

1270. In response to the NOI, 

commenters raised various concerns 

regarding redirects. Among other things, 

customers complained of difficulties 

obtaining redirected service, while 

transmission providers complained of a 

lack of clarity in the rules governing 

redirects. In the NOPR, the Commission 

stated its belief that a number of these 

concerns appeared to have been 

resolved by the adoption of the WEQ 

Standards in Order No. 676, which was 

issued after the NOI. The Commission 

sought comment on whether parties 

believed the WEQ Standards in fact 

addressed those concerns adequately. 

1271. The Commission also stated its 

expectation that a number of other 

concerns raised in response to the NOI, 

while perhaps not yet addressed (or 

addressed fully) by a WEQ Standard, are 

nevertheless the types of issues that are 

appropriate for the WEQ process. The 

Commission therefore proposed that 

each commenter that continued to 

believe additional reform is necessary 

with regard to redirects evaluate 

whether its concerns would more 

appropriately be addressed by the WEQ 

as it considers its next version of its 

standards.776 The Commission noted 

that WEQ was in the process of 

reevaluating WEQ Standard 001–9.7, 

dealing with redirects and rollovers, so 

that it is consistent with the 

Commission’s guidance given in Order 

No. 676. The Commission requested 

comment on whether the WEQ process, 

along with the guidance provided by the 

Commission in Order No. 676, is 

sufficient to address the concerns of 

commenters that seek clarification on 

the interplay between redirects and 

rollovers. 

1272. In the NOPR, the Commission 

acknowledged that there were 

additional, more fundamental concerns 

with regard to section 22 raised in 

response to the NOI. Customers 

generally argued that their ability to 

redirect to new points is stymied by a 

lack of ATC at the new points or the 

need for major upgrades, or that 

transmission providers take too long to 

process the redirect request. 

Transmission providers, on the other 

hand, complained of the administrative 

burdens and complexity (particularly 

with regard to reliability) of processing 

transmission customers’ short-term 

changes in service and that there is 

often not enough time for the market to 

respond to capacity made available on 

a customer’s original path. The 

Commission stated its belief that other 

proposed reforms in the areas of 

process, transmission planning, and 

ATC calculation should address 

transmission customer concerns 

regarding redirects. The Commission 

encouraged interested parties to submit 

a specific proposal, along with proposed 

revised pro forma OATT language, to 

the extent they believe the proposed 

reforms will not adequately address 

their concerns. 

1273. The Commission also noted in 

the NOPR that several transmission 

providers had posted business practices 

that allow network customers either to 

substitute an off-system non-designated 

resource for a designated resource or to 

redirect the point of receipt associated 

with an existing network resource. The 

Commission proposed that network 

customers not be permitted to redirect 

network transmission service because 

network service involves no identified 

contract path and therefore should not 

be treated as a directable service. 

a. Proposed Reliance on WEQ Process 

and Other OATT Reforms 

Comments 

1274. Commenters generally agree 

with the Commission that issues with 

respect to redirects of firm and non-firm 

transmission service are best addressed 

through the WEQ as established by 

NAESB, in accordance with Order No. 

676 and the WEQ process for creating 

new standards.777 Seattle argues that the 

NAESB standard setting process has 

worked well thus far and, as a result, 

other redirect issues should be first 

referred to NAESB as a standard-setting 

request. MISO states that it has serious 

concerns with the WEQ process and the 

Commission’s unwarranted deference to 

NAESB to develop what will become 

binding business standards and 

practices. 

1275. Nevada Companies recommend 

the following improvements for the 

NAESB process: use of a professional 

facilitator to keep discussions focused 

and moving; and mandatory surveys 

breaking down the sections on proposed 

NAESB standards after the first round of 

comments are received to determine if 

consensus exists on the proposed 

standards, since it appears that there are 

relatively few participants at NAESB 

meetings where standards are being 

drafted and relatively few commenters 

on those draft standards. 

1276. Several commenters state that 

they agree with the Commission’s 

proposal to rely on other proposed 


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778E.g., EEI, NorthWestern, and Seattle. 

779See Standards for Business Practices of 

Interstate Natural Gas Pipelines, Order No. 587–N, 

FERC Stats. & Regs. ¶ 31,125 at P 23 (2002). 

780See Order No. 676 at P 12. 

781TranServ explains that these are two primary 

features in a revised WEQ 001–9.7 standard that 

was open for public comment. 

782 95 FERC ¶ 61,027 at 61,083 (2001). 

783The Commission, however, recognized that 

this flexibility was not unlimited—any change to a 

delivery point is treated as a new request for service 

for purposes of the availability of capacity. 

784 97 FERC ¶ 61,207 at 61,905–06 (2001). 

785 Id. 

reforms in the NOPR to resolve the 

remaining redirect issues.778 Seattle 

generally agrees that the reforms 

proposed in the NOPR should improve 

the ability to assign and use 

transmission on a firm basis. EEI and 

NorthWestern state that the NOPR 

proposal to increase transparency in the 

calculation of ATC should assist 

transmission customers in both 

selecting transmission paths that may be 

available for redirect and understanding 

why certain paths cannot accommodate 

redirect transactions. 

Commission Determination 

1277. The Commission concludes that 

the proposed method for addressing 

remaining concerns with redirects—i.e., 

relying on other reforms adopted in this 

Final Rule and in the Order No. 676 

proceeding—is adequate to ensure that 

transmission providers do not engage in 

undue discrimination when a customer 

seeks to modify its receipt and delivery 

points on a firm basis. As explained 

throughout this Final Rule, the reforms 

adopted herein address the remaining 

opportunities for undue discrimination. 

Planning and ATC reforms will give 

transmission customers more accurate 

and complete ATC information when 

evaluating their redirect options. 

Increased transparency will give 

transmission customers the information 

they need to evaluate a transmission 

provider’s denial of a request to redirect. 

Modifications to the process for 

requesting and securing firm point-topoint service will improve the ability to 

redirect transmission service to new 

points pursuant to section 22 and 

ensure complete and timely responses 

from transmission providers. The 

Commission therefore concludes that no 

further reforms specific to redirects are 

necessary at this time. 

1278. The Commission also concludes 

that the NAESB WEQ is the appropriate 

standard-setting body for developing 

business practices and implementing 

the Commission’s redirect policy. The 

Commission will refrain from 

commenting here on the NAESB process 

itself because we believe that the 

industry is best situated to determine 

how to structure the standard-setting 

process to provide for the widest 

possible participation and consensus. 

We nevertheless clarify that, consistent 

with precedent, NAESB is charged with 

implementing Commission policy 

through business practices.779 The 

Commission finds that the NAESB WEQ 

is an acceptable standards development 

process, representing a cooperative 

effort by industry participants to 

develop business practices that enhance 

the efficiency of the electric grid.780

Where necessary, NAESB participants 

may seek clarification of Commission 

policy so that NAESB may develop the 

appropriate standards. 

b. Redirects and Rollovers Rights 

Comments 

1279. Regarding the interaction 

between redirects and rollovers, some 

commenters request that the 

Commission clarify what they view as 

an inconsistency between Order No. 

676, the Commission’s existing pro 

forma OATT, and the rollover proposal 

in the NOPR. Specifically, Bonneville, 

MISO, and Southern argue that, contrary 

to the pro forma OATT and NOPR, 

Order No. 676 improperly suggested in 

an example that a short-term redirect of 

a long-term service agreement gives the 

customer rollover rights for the new 

path. TranServ supports placing the 

following two conditions on the receipt 

of rollover rights for redirects: a redirect 

on a firm basis must be for one year or 

longer, and the redirect must be for the 

entire remaining term of the parent 

(original) request.781 If these conditions 

are met, TranServ contends that the 

customer will be granted rollover rights 

on the redirect path and lose the 

rollover rights held on the original path. 

If the customer wishes to retain rollover 

rights on the original path, TranServ 

continues, it will have the option to 

submit multiple redirect requests of less 

than one year in duration for the term 

desired. With respect to WEQ Standard 

001.9.7, MISO incorporates by reference 

its opposition to the Commission’s 

adoption of the proposed transfer of 

rollover rights on the redirected path in 

its request for rehearing of Order No. 

676. There MISO argued that there 

should be no rollover rights on a 

redirect path and that the guidance in 

Order No. 676 requiring the 

transmission provider ‘‘to offer rollover 

rights to a customer requesting a firm 

redirect if rollover rights are available 

on the redirect path’’ was inconsistent 

with the pro forma OATT. 

Commission Determination 

1280. Commission policy allows a 

redirect of firm, long-term service to 

retain rollover rights, even if the redirect 

is requested for a shorter period. In 

other words, the rollover right follows 

the redirect, regardless of the duration 

of the redirect. Contrary to the 

comments of Bonneville, MISO, and 

Southern, the Commission did not 

impose this requirement for the first 

time in Order No. 676, but merely 

provided guidance to the industry by 

restating Commission policy on this 

matter. The Commission has explained 

in prior orders that a transmission 

customer making a firm redirect request 

does not convert its original long-term 

firm transmission service to short-term 

service, nor does it lose its rollover 

rights under its long-term firm 

transmission service agreement. The 

Commission’s concern underlying this 

policy is that long-term customers 

should not need to choose between 

redirecting on a firm basis and 

maintaining rollover rights, rather their 

rollover rights should be retained 

consistent with the long-term nature of 

their service. 

1281. In Commonwealth Edison Co., 

the Commission explained that a 

‘‘request to change a delivery point on 

a firm basis for one month and then to 

revert to its original delivery point does 

not convert its existing long-term firm 

transmission service agreement into two 

separate short-term transmission service 

agreements.’’ 782 The Commission stated 

that section 22.2 was intended to 

provide flexibility to transmission 

customers to permit them to react in a 

competitive market and that some 

amount of this flexibility would be lost 

if a long-term firm transmission 

customer seeking to modify its delivery 

points would lose its rollover rights.783

1282. The Commission affirmed this 

policy in American Electric Power 

Service Corp.784 In that case, a long-term 

transmission customer (Exelon) had 

been granted a short-term redirect, but 

denied rollover rights on the redirected 

path. The Commission found the denial 

of rollover rights was improper, since 

the ‘‘redirect request made by Exelon 

did not convert Exelon’s long-term firm 

transmission service to short-term 

service, and, therefore, did not affect 

Exelon’s rollover rights under its longterm firm transmission service 

agreement.’’ 785 Thus, there is no 

inconsistency between the 

Commission’s redirect policy and Order 

No. 676. 


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786 Midwest Independent Transmission System 

Operator, Inc., 118 FERC ¶ 61,095 at P 79–85(2007). 

787See Appalachian Power Co., 39 FERC ¶ 61,296 

(1987). 

c. Redirects as New Requests for Service 

Comments 

1283. With respect to the provision in 

section 22.2 of the pro forma OATT 

specifying that requests to redirect on a 

firm basis be considered new requests 

for service, LPPC and NPPD ask that this 

provision be modified to ensure that a 

customer redirecting its service will 

retain a higher priority for service in the 

transmission provider’s queue than new 

customers. LPPC argues that it is 

inequitable to require customers to 

compete for capacity as though their 

loads were incremental to the system 

when they are simply changing their 

receipt points as a matter of necessity 

(since suppliers may commence serving 

other loads or cease doing business). EEI 

argues on reply that, if LPPC’s proposal 

would give customers priority at new 

points of receipt and delivery regardless 

of whether the redirected service creates 

system impacts different from the old 

service, the proposal would replace 

‘‘first-come, first-served’’ priority with a 

system in which customers would never 

know for sure whether their own 

requests for service would be displaced 

by subsequent requests for redirected 

service. EEI cautions that the 

transmission system simply cannot be 

planned and constructed with enough 

spare capacity to allow any customer to 

redirect service to any point that it 

chooses at any time. 

1284. Bonneville similarly argues that 

a redirect request should meet the same 

term and notice requirements as a new 

request given that the transmission 

provider’s planning horizon and the 

amount of time needed to remarket 

unused capacity is no different for a 

redirect and a new transmission service 

request. APPA argues on reply that it is 

unclear how Bonneville’s request would 

affect load-serving transmission 

customers that cannot obtain power 

supply agreements of a term sufficient 

to dovetail with the term requirements 

for a new request. Imperial recommends 

that redirects be evaluated using ATC at 

the time of the redirect request, like any 

other new request for service, but that 

the transmission provider be given 

additional time to determine whether 

native load growth will prevent rollover 

rights for the redirects. 

Commission Determination 

1285. Section 22.2 of the pro forma 

OATT provides that redirects ‘‘shall be 

treated as a new request for service in 

accordance with section 17,’’ except that 

the transmission customer may not be 

required to pay an additional deposit in 

certain circumstances. Therefore, a 

redirect right does not grant the 

customer access to system capacity or 

queue position different from other 

customers submitting new requests for 

service. A redirect request must be 

evaluated in accordance with section 17 

using the same system assumptions and 

analysis applicable to any other new 

request for service, including whether 

sufficient ATC exists to accommodate 

the request. The Commission concludes 

it would be inappropriate, and contrary 

to the pro forma OATT, to grant 

redirects special queue treatment. 

1286. Regarding Imperial’s request 

that transmission providers be given 

additional time to determine whether 

native load growth will prevent rollover 

rights for the redirects, we find that 

redirects should be studied like any 

other new request for firm point-topoint service. Transmission providers 

must examine whether any request, a 

firm redirect request or a new service 

request, would be affected by future 

native load growth resulting in possible 

rollover rights restrictions, so we see no 

need to provide additional time for 

transmission provider analysis of firm 

redirect request. 

d. Pricing for Redirects 

Comments 

1287. TranServ requests that the 

Commission resolve a disagreement 

among WEQ participants regarding the 

pricing of redirects as requests for new 

service. TranServ asks whether the 

failure to charge an incremental uplift 

between the original and redirected rate 

(e.g., respectively, the monthly rate and 

daily on-peak rate) would constitute the 

offering of a discount for daily service 

that in turn must be posted for all other 

paths to the same point of delivery. 

TranServ argues that it is reasonable to 

charge an incremental uplift such that 

the rate paid by the redirect customer 

would be on par with that paid by any 

other transmission customer reserving 

(daily) short-term firm service of like 

duration (i.e., a ‘‘new request for 

service’’), and the customer would pay 

the difference between the daily onpeak rate and 1/30th of the monthly 

rate. 

1288. Southern argues that, with 

respect to the price for redirects, if 

redirected hourly firm service is more 

valuable than firm service, economic 

theory would dictate that customers 

should be required to pay for that added 

value. 

Commission Determination 

1289. The Commission has not 

established a single, industry-wide 

pricing policy for redirects and did not 

propose a pricing policy in the NOPR. 

As a result, a uniform pricing method 

for redirects is beyond the scope of this 

proceeding. Nevertheless, we note that 

the Commission explained in a recent 

order that its policy does not allow 

transmission providers to collect 

additional charges when a firm point-topoint customer redirects on a non-firm 

basis.786 The Commission concluded 

that it would not subject non-firm 

redirects to the Appalachian Method of 

pricing,787 which is premised on the 

assumption that a customer using the 

transmission system for the 16 peak 

hours of the day should pay the same 

contribution to fixed costs as a customer 

who has reserved capacity on a daily 

basis. This is because the redirecting 

customer already would have paid for 

firm service over all on-peak and offpeak hours during the reservation 

period of its service, therefore, there is 

no need to ensure that the customer 

pays a premium for the opportunity to 

cherry pick the best hours each day. 

Furthermore, because the Commission 

is not requiring the provision of hourly 

firm service, Southern’s argument 

regarding redirected hourly firm service 

is now moot. 

e. Other Issues 

Comments 

1290. EEI agrees with the 

Commission’s proposal to clarify that 

network customers may not redirect 

network transmission service. Alberta 

Intervenors contend that undue 

discrimination remains because the 

flexibility to modify points of receipt 

and delivery that the network customer 

enjoys through ‘‘parking’’ and 

‘‘hubbing’’ is not likewise granted to a 

point-to-point customer. Alberta 

Intervenors recommends that the pro 

forma OATT either make a common 

service available to all participants (not 

just network customers) or prohibit 

network customers from using point-topoint services for parking and hubbing. 

1291. Imperial asks the Commission 

to clarify that a transmission customer 

should not be able to make multiple 

redirects. Imperial explains that this 

clarification would address two 

concerns: multiple short-term changes 

raise reliability concerns and often there 

is insufficient time for the released 

capacity to be used by another 

customer; and the burden on properly 

scheduling for reliability increases 

exponentially when there are redirects 

of redirects. 


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788Order No. 888–A at 30,260. 

789E.g., ELCON, Suez Energy NA, Powerex, 

Seattle, TAPS, Constellation, Entegra, NRECA, TDU 

Systems, Regional Electricity Committee, MISO, 

MidAmerican, FirstEnergy, Tacoma, EEI, Nevada 

Companies, and TranServ. 

1292. MISO/PJM States argue that 

because RTOs are not likely to engage in 

discrimination with respect to redirects, 

the Commission should not modify RTO 

redirect policies in the instant 

rulemaking proceeding. 

Commission Determination 

1293. The Commission adopts the 

NOPR proposal and finds that network 

customers may not redirect network 

service in a manner comparable to the 

way customers redirect point-to-point 

service. Unlike point-to-point service, 

network service involves no identified 

contract path and thus is not a 

directable service. A network customer 

seeking to substitute one resource for 

another already has the ability under the 

pro forma OATT to terminate its 

existing designation and designate a 

new resource on an as-available basis. If 

necessary, the network customer may 

then request to redesignate its original 

network resource by making a request to 

designate a new network resource. 

Alternatively, the network customer 

could use secondary network service if 

it wants to substitute a non-designated 

network resource for a designated 

network resource on an as-available 

basis. 

1294. For similar reasons, the 

Commission denies Alberta Intervenors’

request. The Commission has explained 

that customers must choose between 

point-to-point and network services, 

each of which has its own advantages 

and risks.788 The Commission declined 

to implement a single form of 

transmission service in Order No. 888, 

concluding that point-to-point and 

network services are the appropriate 

base-line services under the pro forma 

OATT, and Alberta Intervenors offer no 

justification for departing from that 

approach now. Alberta Intervenors 

parking and hubbing related arguments 

alleging that network service is 

commonly used to purchase power 

intended for sales to third parties is 

addressed in section V.D.7 of this Final 

Rule. Although we deny Alberta 

Intervenors’ request, we expect that the 

reforms adopted in this Final Rule will 

provide point-to-point customers with 

increased service options and flexibility. 

1295. Implementing Imperial’s 

proposal would prevent customers from 

redirecting for a short period or periods 

of time and then redirecting back to 

their original points, making redirects a 

less valuable option for customers. 

Multiple redirects are allowed only if 

the customer can meet the scheduling 

and other requirements for new requests 

for service under the pro forma OATT. 

As long as the customer meets these 

requirements, the Commission believes 

that the ability to redirect service does 

not present an unreasonable burden to 

transmission providers. As for 

applicability to RTOs and ISOs, we 

explain our compliance requirements in 

section IV.C of this Final Rule. To the 

extent an RTO’s or ISO’s redirect policy 

does not conform to the pro forma 

OATT, as amended by this Final Rule, 

the RTO or ISO must demonstrate that 

its policy is consistent with or superior 

to the pro forma provisions in 

accordance with the compliance 

procedures set forth in that section. 

5. Acquisition of Transmission Service 

a. Processing of Service Requests 

1296. The pro forma OATT includes 

requirements that transmission 

providers process requests for 

transmission service in a timely fashion. 

Section 17.5 (Response to a Completed 

Application) and section 18.4 

(Determination of Available 

Transmission Capability) of the pro 

forma OATT provide that following the 

receipt of a completed application for 

service, the transmission provider must 

respond to transmission customer 

requests for determinations of the 

availability of firm and non-firm 

transmission capacity on a timely basis. 

The transmission provider must make 

the determination as soon as reasonably 

practicable after receipt but no later 

than certain specified time periods (or 

such time periods generally accepted in 

the region). 

1297. Section 19 (Additional Study 

Procedures for Firm Point-to-Point 

Transmission Service Requests) of the 

pro forma OATT provides deadlines 

that transmission providers must adhere 

to in issuing system impact study 

agreements and facilities studies 

agreements and that transmission 

customers must abide by in responding 

to these study agreements. Section 19 

requires transmission providers to use 

due diligence to complete system 

impact studies and facilities studies 

within 60 days. Section 32 of the pro 

forma OATT (Additional Study 

Procedures for Network Integration 

Transmission Service Requests) 

contains similar due diligence deadlines 

for completing system impact studies 

and facilities studies associated with 

requests for network service. 

(1) Posting Performance Metrics 

NOPR Proposal 

1298. In the NOPR, the Commission 

proposed to require transmission 

providers to post on their OASIS sites 

metrics that track their performance in 

processing system impact studies and 

facilities studies associated with 

requests for transmission service. The 

Commission proposed that transmission 

providers calculate the proposed 

performance metrics separately for 

affiliates and non-affiliates and for 

requests for short-term and long-term 

transmission service. 

1299. In addition, the Commission 

proposed to require a notification filing 

and the posting of additional metrics if 

a transmission provider completes more 

than 20 percent of non-affiliates’ studies 

outside of the 60-day due diligence 

deadline in the pro forma OATT for two 

consecutive quarters. Starting the 

quarter after a notification filing, the 

transmission provider would be 

required to post the following 

information on OASIS: (1) The average, 

across completed system impact studies, 

of the employee-hours expended per 

completed system impact study, (2) the 

average, across completed facilities 

studies, of employee-hours expended 

per completed facilities study, (3) the 

number of employees devoted to 

processing system impact studies, and 

(4) the number of employees devoted to 

processing facilities studies. The 

Commission proposed that transmission 

providers post these additional 

performance metrics until they process 

at least 90 percent of all system impact 

and facilities studies within 60 days 

after the study agreement has been 

executed. The additional performance 

metrics also would be calculated 

separately for affiliates’ and nonaffiliates’ requests for transmission 

service and for short-term and long-term 

transmission service. 

Comments 

Standard Performance Metrics 

1300. Transmission customers and a 

number of other commenters generally 

support or do not oppose the 

Commission’s proposal to require 

transmission providers to post 

performance metrics.789

1301. Southern and Salt River oppose 

the proposal, arguing that most of the 

data needed to compute the metrics is 

already available on OASIS. Southern 

asserts that the NOPR does not explain 

why the currently available information 

is inadequate or how the proposed 

metrics would not be duplicative and, 

thus, does not fully justify the need for 

reform. Southern also argues that the 

Commission’s proposal will impose 


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790E.g., CREPC, MISO, Constellation, and TDU 

Systems. 

791 372 F.3d 395, 404 (D.C. Cir. 2004). 

costs and burdens on transmission 

providers, and ultimately those who use 

their services, that do not correspond 

with the limited benefits that might be 

gained. Salt River believes that 

performance tracking requirements 

should be established on a case-by-case 

basis in response to complaints. 

NorthWestern believes the 60 days 

should be a target, but not a deadline, 

and, as such, transmission providers 

should not be required to report 

performance metrics that summarize the 

time they take to perform the studies. 

1302. Several commenters requested 

clarification on certain features of the 

Commission’s proposal. Nevada 

Companies asks the Commission to be 

very specific as to what statistical data 

items are to be reported on the OASIS 

so that transmission providers do not 

inadvertently violate the confidentiality 

of their transmission customers. PNMTNMP requests clarification that the 

standards set out in the NOPR are solely 

applicable to processing of transmission 

delivery service requests, and not to 

interconnection service requests. Insofar 

as the Commission determines that 

performance metrics should be posted, 

Southern asks the Commission to clarify 

that the proposed posting of 

performance metrics also would be 

required of RTOs and ISOs. 

1303. A number of commenters 

suggest that the Commission modify the 

performance metrics that transmission 

providers are required to post. EEI 

suggests that NAESB develop the 

metrics that transmission providers are 

required to post, using the metrics 

contained in the NOPR as guidance. EEI 

and MidAmerican suggest that the 

performance metrics include 

information about the degree to which 

transmission customers delay the study 

process. MISO suggests that 

transmission providers post metrics 

related to the time transmission 

customers take to respond to the results 

of completed system impact studies and 

facilities studies. Southern asserts that 

fewer metrics should be required and 

that they should relate directly to the 

study-timing concerns raised in the 

NOPR. Bonneville and MISO argue that 

transmission providers should not have 

to post information about the cost of 

transmission system upgrades 

recommended in the request studies. 

Bonneville believes that the average cost 

of recommended upgrades is misleading 

because it will mask the wide variation 

in such costs. MISO suggests that 

transmission providers also report the 

standard deviation for study completion 

times. Southern asserts further that the 

OATT does not specifically provide for 

a system impact study or facilities study 

to be performed on a short-term basis, 

so any metrics required as part of OATT 

reform should not include short-term 

requests. CREPC suggests that 

performance metrics be calculated 

separately for renewable resources. 

1304. Several commenters suggest 

that transmission providers post 

additional information to further 

enhance transparency. A number of 

commenters suggest that the 

Commission require the posting of the 

disposition of all transmission service 

requests, including those not requiring 

studies.790 TDU Systems suggest that 

the Commission require transmission 

providers to post the parameters of each 

denied request. MISO suggests that 

transmission providers provide a 

narrative to explain any anomalous 

study costs that may affect the posted 

average cost. If a transmission provider 

anticipates that it will miss the study 

deadline date, NRECA suggests that it 

should post that information, the 

expected finish date, and a reason for 

not being able to meet the deadline. 

1305. EEI recommends that the 

Commission delegate to NAESB the 

responsibility for developing the 

Standard and Communications 

Protocols, business practices and OASIS 

modifications that will be necessary to 

provide the metrics. 

Additional Performance Metrics (After 

Two Quarters of Late Studies) 

1306. EEI and Southern oppose the 

Commission’s proposal to require 

transmission providers that fail to 

complete studies in a timely manner to 

post additional performance metrics 

that measure the labor input used to 

complete studies. EEI asserts that there 

is little value to be gained from posting 

the additional information that the 

Commission proposes. EEI believes the 

information concerning the number of 

employees who perform studies will not 

be determinative of responsibility for 

the delay because the significant issue is 

whether the number of studies that the 

transmission provider is required to 

perform or the total amount of time 

needed to perform studies has increased 

significantly or whether customers 

caused the delays. Southern questions 

the Commission’s legal authority to 

require transmission providers that do 

not complete studies in a timely manner 

to post additional performance metrics, 

citing Cal. Ind. Sys. Operator Corp. v. 

FERC.791 Southern characterizes the 

Commission’s proposal as a punishment 

for delays in processing request studies. 

1307. Several other commenters 

suggest changes to the Commission’s 

proposal. Southern believes the 

submission of a notification of 

extenuating circumstances should 

suspend the obligation to post the 

additional metrics proposed in the 

NOPR. EEI and Southern argue that the 

Commission should be certain that it is 

collecting such information only from 

those transmission providers that, for no 

other reason except themselves, fail to 

consistently evaluate studies within the 

60-day due diligence period. Therefore, 

if a transmission provider demonstrates 

that delays in completing studies are 

due to extenuating circumstances, then 

EEI and Southern believe the 

Commission should not require the 

transmission provider to post the 

additional metrics. MISO believes the 

Commission should exempt RTOs from 

the additional employee performance 

metrics proposed in the NOPR for the 

same reason that the Commission 

proposed to exempt RTOs from 

operational penalties for untimely 

completion of studies, as MISO claims 

the additional posting requirements are 

in the nature of penalty. Bonneville 

believes the proposed metrics will be 

misleading whenever a transmission 

provider employs outside consultants to 

perform or assist with studies. 

Therefore, Bonneville suggests that the 

Commission add two other metrics, the 

number of studies performed entirely by 

consultants and, in the case of studies 

performed by a combination of 

employees and consultants, the average 

percentage of the study performed by 

consultants. 

Commission Determination 

Standard Performance Metrics 

1308. The Commission will require 

transmission providers to post the 

performance metrics proposed in the 

NOPR, as modified by this Final Rule. 

The proposed metrics will enhance the 

transparency of the study process and 

shed light on whether transmission 

providers are processing request studies 

in a non-discriminatory manner. We 

also agree with comments by 

MidAmerican and EEI that transmission 

providers should be able to track delays 

in the study process caused by 

transmission customers. Doing so will 

allow the Commission and market 

participants to determine the extent to 

which delays by transmission customers 

are causing transmission providers to 

process request studies on an untimely 

basis, which will add needed 

transparency to the study process. 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12435 

792The OASIS template transstatusaudit is 

defined in the Standards and Communications 

Protocols section of NAESB’s WEQ Business 

Practice Standards. The template transstatusaudit is 

the audit component to OASIS template transstatus 

and, as such, contains information regarding the 

Continued 

Therefore, we will revise the 

performance metrics transmission 

providers are required to post to include 

metrics that track delays by 

transmission customers. 

1309. Transmission providers will be 

required to post the performance 

metrics, outlined below, for each 

calendar quarter. Transmission 

providers will be required to begin 

tracking their performance upon the 

effective date of this Final Rule and 

keep the quarterly performance metrics 

posted on their OASIS sites for three 

calendar years. The transmission 

provider will be required to post the 

quarterly performance metrics within 15 

days of the end of the quarter. The 

performance metrics outlined below 

must be calculated separately for 

affiliates’ and non-affiliates’ requests, in 

order to identify potential instances 

when the transmission provider is 

processing requests on a discriminatory 

basis. The transmission provider is 

required to aggregate studies associated 

with requests for short-term and longterm transmission service when 

calculating the metrics defined below. 

While a transmission provider could 

offer to study a request for short-term 

firm point-to-point transmission service, 

we acknowledge that the transmission 

customer often is unwilling to pay for 

such a study. Therefore, to ease the 

reporting burden, the transmission 

provider is not required to report the 

performance metrics defined below 

separately for requests for short-term 

and long-term firm point-to-point 

transmission service. A transmission 

provider is also required to post 

performance metrics for studies that it 

conducts for RTOs. 

1310. A transmission provider is 

required to post the following set of 

performance metrics on a quarterly 

basis: 

• Process time from initial service 

request to offer of system impact study 

agreement pursuant to sections 17.5, 

19.1 and 32.1 of the pro forma OATT 

Æ Number of new system impact 

study agreements delivered to 

transmission customers 

Æ Number of new system impact 

study agreements delivered to the 

transmission customer more than 

30 days after the transmission 

customer submitted its request 

Æ Average time (days) from request 

submittal to change in request 

status 

Æ Average time (days) from request 

submittal to delivery of system 

impact study agreement 

Æ Number of new system impact 

study agreements executed 

• System impact study processing 

time pursuant to sections 19.3 and 32.3 

of the pro forma OATT 

Æ Number of system impact studies 

completed 

Æ Number of system impact studies 

completed more than 60 days after 

receipt of executed system impact 

study agreement 

Æ Average time (days) from receipt of 

executed system impact study 

agreement to date when completed 

system impact study made available 

to the transmission customer 

Æ Average cost of system impact 

studies completed during the 

period 

• Service requests withdrawn from 

system impact study queue 

Æ Number of requests withdrawn 

from the system impact study queue 

Æ Number of system impact studies 

withdrawn more than 60 days after 

receipt of executed system impact 

study agreement 

Æ Average time (days) from receipt of 

executed system impact study 

agreement to date when request was 

withdrawn from the system impact 

study queue 

• For all system impact studies 

completed more than 60 days after 

receipt of executed system impact study 

agreement, average number of days 

study was delayed due to transmission 

customer’s actions (e.g., delays in 

providing needed data) 

• Process time from completed 

system impact study to offer of facilities 

study pursuant to sections 19.4 and 32.4 

of the pro forma OATT 

Æ Number of new facilities study 

agreements delivered to 

transmission customers 

Æ Number of new facilities study 

agreements delivered to 

transmission customers more than 

30 days after the completion of the 

system impact study 

Æ Average time (days) from 

completion of system impact study 

to delivery of facilities study 

agreement 

Æ Number of new facilities study 

agreements executed 

• Facilities study processing time 

pursuant to sections 19.4 and 32.4 

Æ Number of facilities studies 

completed 

Æ Number of facilities studies 

completed more than 60 days after 

receipt of executed facilities study 

agreement 

Æ Average time (days) from receipt of 

executed facilities study agreement 

to date when completed facilities 

study made available to the 

transmission customer 

Æ Average cost of facilities studies 

completed during the period 

Æ Average cost of recommended 

upgrades for facilities studies 

completed during the period 

• Service requests withdrawn from 

facilities study queue 

Æ Number of requests withdrawn 

from the facilities study queue 

Æ Number of facilities studies 

withdrawn more than 60 days after 

receipt of executed facilities study 

agreement 

Æ Average time (days) from receipt of 

executed facilities study agreement 

to date when request was 

withdrawn from the facilities study 

queue 

• For all facilities studies completed 

more than 60 days after receipt of 

executed facilities study agreement, 

average number of days study was 

delayed due to transmission customer’s 

actions (e.g., delays in providing needed 

data). 

1311. In response to Nevada 

Companies request that we clarify the 

statistical data items that are to be 

reported on OASIS pursuant to the 

Commission’s proposal, we reiterate 

that transmission providers are required 

to provide summary data as defined 

above. We do not believe these data will 

violate the confidentiality of any 

transmission customer, even in the 

event the transmission provider has 

worked on a limited number of studies. 

We clarify that the performance metrics 

posting requirement discussed above is 

solely applicable to processing of 

transmission delivery service requests, 

and not to interconnection service 

requests. Finally, we clarify that RTOs 

and ISOs also are required to post the 

performance metrics described above. 

As we discuss below, we believe all 

transmission providers should be 

subject to the same reporting 

requirements. 

1312. We disagree with Southern and 

Salt River which argue that the data 

already on OASIS is sufficient to 

accomplish our goal to enhance 

transparency of the transmission 

provider’s request study processing. 

First, the data available on the OASIS 

template transstatusaudit does not 

contain the information necessary to 

calculate all of the performance metrics 

proposed in the NOPR.792 For instance, 


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type of transmission service requested, affiliate 

status, date and time the transmission service was 

requested, and the date and time of all changes in 

request status (e.g., place in study mode, confirmed 

or withdrawn). 793 18 CFR 37.7(b). 

794E.g., Constellation, EPSA NOI Comments, 

Arkansas Cities NOI Comments, APPA NOI Reply 

Comments, and Powerex NOI Reply Comments 795 

As noted in P 1318, we direct public utilities 

working through NAESB to develop protocols for 

posting the performance metrics required here so 

they will be posted in a consistent fashion. 

795 As noted in P 1318, we direct public utilities 

working through NAESB to develop protocols for 

posting the performance metrics required here so 

they will be posted in a consistent fashion. 

796 18 CFR 37.6(b)(2)(iii). 

transstatusaudit allows one to 

determine when a request was moved 

from ‘‘received’’ to ‘‘study’’ and then to 

‘‘accepted’’ or ‘‘counteroffer’’. 

Depending on when the transmission 

provider moves the request into 

‘‘study,’’ this information does not allow 

one to determine either whether the 

transmission provider provided a 

system impact study agreement within 

30 days or whether the transmission 

provider completed the system impact 

study within 60 days. In addition, the 

transmission provider is required to 

make the data in transstatusaudit 

available on OASIS for only 90 days and 

available by request for three years.793

As a result, market participants would 

be required to calculate the performance 

metrics they desire on a quarterly basis 

if they want to use just the data posted 

on OASIS. Finally, downloading 

transstatusaudit data for specific OASIS 

requests that required a system impact 

study or feasibility study can be 

cumbersome due to the manual nature 

of the download process. The 

transmission provider has the data 

necessary to calculate the proposed 

performance metrics readily available. 

We believe it is more efficient for a 

single transmission provider to calculate 

the performance metrics for its system 

rather than have multiple interested 

parties calculate the performance 

statistics for each transmission provider 

of interest. 

1313. We also disagree with 

Southern’s assertion that the costs and 

burdens to transmission providers are 

not justified by the benefits that might 

be gained. We are concerned that, under 

the existing pro forma OATT, 

transmission providers do not have 

adequate incentives to conduct studies 

on a timely and nondiscriminatory 

basis. First, transmission providers have 

incentives to discriminate against third 

parties and in favor of their affiliates 

(i.e., to delay the study requests of 

nonaffiliates, but act more quickly on 

those of its affiliates). Second, 

transmission providers also can lack 

incentives to provide sufficient staff 

resources to support increasing 

demands in the study process. Given 

that most of the costs associated with 

the study process are operational, 

transmission providers, at most, will 

recover those costs without profit (i.e., 

a return) and, if the demands of the 

study process are increasing, fail to 

recover such cost increases if the 

transmission provider is between rate 

cases. We therefore believe that there 

are several reasons that greater 

transparency is required to provide the 

correct incentives to comply with the 

pro forma OATT provisions respecting 

studies. 

1314. We also note that virtually all 

commenters agree with our proposal to 

require transmission providers to 

calculate the above performance 

metrics. This support stems, in part, 

from transmission customers’

perception that transmission providers 

do not exert sufficient effort to complete 

requests in a timely manner.794 Delays 

in processing study requests can cause 

customers to incur material financial 

damage. Moreover, the data needed to 

calculate the required performance 

statistics is readily available to the 

transmission provider and, therefore, 

the cost to the transmission provider 

will be small relative to the benefits of 

enhanced transparency and assurance 

that the transmission provider is 

processing request studies in a timely 

and non-discriminatory fashion. 

1315. Based on our experience and 

the comments received in response to 

the NOI and NOPR, the Commission 

believes the steps we take here are 

necessary to increase transparency for 

the processing of service requests by all 

transmission providers. It would be 

inappropriate, as some commenters 

suggest, to wait for specific complaints 

about specific transmission providers 

before requiring the transmission 

provider to calculate the performance 

metrics defined above. We conclude 

that the reporting requirements adopted 

in this Final Rule must be applied to all 

transmission providers in order to 

enhance the transparency of the study 

process and ensure that transmission 

provider processes study requests in a 

timely and non-discriminatory fashion 

for all transmission customers. The fact 

that the 60-day timeframe in the pro 

forma OATT is a target and not a 

deadline does not change the fact that 

requiring all transmission providers to 

post the performance metrics defined 

above will enhance the transparency of 

the study process. 

1316. We will not adopt any of the 

changes to the proposed performance 

metrics requested by commenters, other 

than adding metrics to track delays by 

customers as discussed above. The 

Commission is in a better position to 

determine the specific performance 

metrics that will achieve our policy 

goals and thus we will not request that 

NAESB develop the metrics to be 

posted.795 We believe the set of 

performance metrics we have chosen 

strike the appropriate balance between 

requiring information that will enhance 

transparency and help ensure that the 

transmission provider is processing 

request studies in a timely and nondiscriminatory fashion while limiting 

the burden the transmission provider 

faces. For instance, we believe the 

performance metrics that address the 

cost of system impact studies and 

facilities studies as well as the cost of 

any proposed transmission upgrades 

can be calculated with relatively little 

effort by the transmission provider and 

should provide meaningful benefits to 

transmission customers. The 

transmission provider readily knows the 

cost of studies it completes and the 

costs of proposed system upgrades and 

summaries of this information should 

enhance the transmission customer’s 

ability to decide whether to submit a 

request for service that may result in a 

study offer. 

1317. We do not believe the relative 

benefits and burdens justify requiring 

the transmission provider to post 

performance metrics beyond those 

adopted in this Final Rule. For instance, 

requiring the transmission provider to 

calculate additional summary 

information or post long narratives to 

explain anomalous upgrade costs do not 

appear necessary at this time to achieve 

our stated policy goals, particularly 

since transmission customers can 

request data associated with completed 

system impact studies and facilities 

studies pursuant to section 

37.6(b)(2)(iii) of the Commission’s 

regulations.796 In addition, we do not 

believe transmission customers, beyond 

the transmission customer directly 

affected, would benefit from the 

information NRECA suggests the 

transmission provider should be 

required to post when it anticipates that 

it will not complete a study within the 

60-day due diligence timeframe. Section 

19.3 of the pro forma tariff already 

requires the transmission provider to 

notify the affected transmission 

customer when it will not be able to 

complete a study within the 60-day due 

diligence timeframe, provide an 

expected completion date, and explain 

why additional time is needed. We do 


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797 For instance, if the transmission provider 

completes 4 non-affiliates’ system impact studies 

during the quarter with 2 completed more than 60 

days after the system impact study agreement was 

executed and completes 2 non-affiliates’ facilities 

studies during the quarter with none completed 

more than 60 days after the facilities study 

agreement was executed, then the transmission 

provider will be deemed to have completed 2 out 

of 6 (33 percent) studies outside of the deadlines 

in the pro forma OATT. 

798E.g., Constellation, EPSA NOI Comments, 

Arkansas Cities NOI Comments, APPA NOI Reply 

Comments, and Powerex NOI Reply Comments. 

not believe other transmission 

customers would benefit enough from 

this information to justify requiring the 

transmission provider to post it. 

Similarly, we do not believe the benefit 

to market participants justifies the 

burden of requiring transmission 

providers to calculate performance 

metrics separately for renewable 

resources. 

1318. We agree, however, with EEI’s 

recommendation that the Commission 

delegate to NAESB the responsibility for 

developing the Standard and 

Communications Protocols, business 

practices and OASIS modifications that 

will be necessary to provide the 

performance metrics adopted above. 

NAESB is in the best position to 

develop the standards and the processes 

by which the performance metrics are 

posted. 

Additional Performance Metrics (after 

two quarters of late studies) 

1319. The Commission also adopts 

the NOPR proposal to require 

transmission providers to submit a 

notification filing with the Commission 

in the event the transmission provider 

processes more than 20 percent of nonaffiliates’ studies outside of the 60-day 

due diligence deadlines in the pro 

forma OATT for two consecutive 

quarters. This filing must be filed within 

30 days of the end of the second quarter 

during which the transmission provider 

processes more than 20 percent of nonaffiliates’ studies outside of the 60-day 

due diligence deadlines in the pro 

forma OATT. For the purposes of 

calculating this notification trigger, the 

transmission provider is required to 

aggregate all system impact studies and 

facilities studies that it completes 

during the quarter for non-affiliates.797

The transmission provider may explain 

in its notification filing that it believes 

there are extenuating circumstances that 

prevented it from meeting the deadlines 

in the pro forma OATT. 

1320. As the Commission proposed in 

the NOPR, starting the quarter following 

a notification filing, the transmission 

provider will be required to post: (1) 

The average, across completed system 

impact studies, of the employee-hours 

expended per completed system impact 

study; (2) the average, across completed 

facilities studies, of employee-hours 

expended per completed facilities 

study; (3) the number of employees 

devoted to processing system impact 

studies; and (4) the number of 

employees devoted to processing 

facilities studies. The transmission 

provider is not required to post these 

additional performance metrics 

separately for affiliates’ and nonaffiliates’ requests for transmission 

service and for short-term and long-term 

transmission service. The transmission 

provider is instead required to aggregate 

studies associated with requests for 

short-term and long-term transmission 

service when calculating these 

additional metrics. The transmission 

provider is not required to post the 

additional metrics if the Commission 

concludes that delays in completing 

studies are due to extenuating 

circumstances. However, the 

transmission provider is required to 

post the additional metrics while the 

Commission considers the transmission 

provider’s notification filing arguing 

that extenuating circumstances 

prevented it from processing request 

studies on a timely basis. Based on the 

timing described in this Final Rule, the 

transmission provider will be required 

to post the additional performance 

metrics approximately two months after 

the provider makes its notification 

filing. The Commission will have this 

time to evaluate the transmission 

provider’s contention that it was unable 

to complete request studies due to 

extenuating circumstances. As a result, 

we expect the transmission provider 

with legitimate extenuating 

circumstances typically will not have to 

post any additional metrics. 

1321. We disagree with those arguing 

that information concerning the number 

of employees who perform studies will 

not be determinative of responsibility 

for the delay. The transmission provider 

will have the right to establish that it is 

unable to perform studies in a timely 

manner because of factors outside its 

control. We received a number of 

comments to the NOPR and NOI that 

suggest that transmission customers 

believe transmission providers fail to 

complete studies on a timely basis 

because they do not have sufficient staff 

to perform the studies.798 As explained 

above, this is one of the concerns that 

has led us to adopt these reforms. The 

additional metrics will serve to shed 

light on the transmission provider’s 

resource commitment, enhance the 

transparency of the study process, and 

increase the transmission provider’s 

incentive to staff its study function 

appropriately. 

1322. The additional posting 

requirement is not a penalty or a 

punishment. We opted not to require 

the transmission provider to post these 

additional performance metrics on a 

regular basis out of a desire to limit the 

transmission provider’s reporting 

burden. However, once the transmission 

provider has stopped completing 

studies on a timely basis, we believe the 

enhanced transparency justifies the 

additional reporting burden. As a result, 

ISOs and RTOs also will be required to 

post the additional performance metrics 

described above. We disagree with 

Southern’s argument that we lack 

jurisdiction to require additional 

posting. The posting requirements are 

directly related to pro forma OATT 

obligations that are necessary to remedy 

undue discrimination and, hence, 

necessarily derive from our broad 

discretion in fashioning remedies to 

undue discrimination. We are not 

attempting to dictate a transmission 

provider’s internal staffing decisions; 

rather, we illuminate the transmission 

provider’s compliance with its pro 

forma OATT obligations to perform 

studies within certain deadlines and on 

a nondiscriminatory basis. 

1323. We will not add the two other 

metrics suggested by Bonneville 

regarding the number of studies 

performed entirely by consultants and, 

in the case of studies performed by a 

combination of employees and 

consultants, the average percentage of 

the study performed by consultants. 

Rather, transmission providers should 

include the time spent by consultants 

on studies in the performance metrics 

defined above. 

(2) Operational Penalties for Late 

Studies 

NOPR Proposal 

1324. The Commission proposed to 

impose operational penalties when 

transmission providers routinely fail to 

meet the 60-day due diligence deadlines 

prescribed in sections 19.3, 19.4, 32.3 

and 32.4 of the pro forma OATT. Under 

the proposal, a transmission provider 

who processes more than 20 percent of 

non-affiliates’ studies outside of the 60- 

day due diligence deadlines in the pro 

forma OATT for two consecutive 

quarters would be required to notify the 

Commission. In this notification filing, 

the transmission provider may explain 

that it believes there are extenuating 

circumstances that prevented it from 

meeting the deadlines in the pro forma 

OATT. The transmission provider 


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799 The transmission provider would be deemed 

to be out of compliance if it completes 10 percent 

or more of non-affiliates’ system impact studies and 

facilities studies outside of the deadlines prescribed 

in the pro forma OATT. 

800E.g., EEI, MidAmerican, Entergy, Southern, 

Imperial, NorthWestern, PNM–TNMP, Salt River, 

and Bonneville Reply. 

801E.g., EEI, Southern, and PNM–TNMP Reply. 

802E.g., MidAmerican, Southern, Imperial, and 

EEI Reply. 

803E.g., MidAmerican, Southern, NorthWestern, 

Northwest IOUs, and PNM–TNMP Reply. 

804E.g., MidAmerican, Southern, and EEI Reply. 

805E.g., EEI, Southern, Northwest IOUs, and 

MidAmerican. 

806E.g., EEI and MidAmerican. 

807E.g., Suez Energy NA, TAPS, Constellation, 

Entegra, TDU Systems, CREPC, and Nevada 

Companies. 

would be subject to an operational 

penalty if it continues to be out of 

compliance 799 with the deadlines 

prescribed in the pro forma OATT for 

each of the two quarters following its 

notification filing. 

1325. The Commission proposed that 

the operational penalty be assessed on 

a quarterly basis, starting with the 

quarter following the notification filing 

and continuing until the transmission 

provider completes at least 90 percent of 

all studies within 60 days after the 

study agreement has been executed. For 

any system impact study or facilities 

study completed during that quarter and 

more than 60 days after the study 

agreement was executed, the 

Commission proposed a penalty equal 

to $500 for each day the transmission 

provider takes to complete the study 

beyond 60 days. For any system impact 

study or facilities study that is still 

pending at the end of the quarter and 

that has been in the study queue for 

more than 60 days, the Commission 

proposed a penalty equal to $500 for 

each day the study has been in the study 

queue beyond 60 days. 

1326. In addition to the proposed 

operational penalties, the Commission 

indicated that it would order other 

remedial actions, consistent with the 

Policy Statement on Enforcement, to be 

determined on a case-by-case basis. The 

Commission proposed that RTOs not be 

subject to this penalty regime because of 

the RTOs’ independence. 

Comments 

1327. Transmission providers 

generally oppose the Commission’s 

proposal.800 Some opponents argue that, 

to the extent the Commission is going to 

impose penalties, it should do so on a 

case-by-case basis.801 Opponents cite a 

number of reasons the Commission 

should not impose the proposed 

operational penalty regime. Several 

opponents caution that imposing a 

penalty may lead transmission 

providers to either prematurely deny a 

request or accept a request to the 

detriment of system reliability.802

Several opponents argue that many 

transmission requests introduce unique 

complexities into the study process, so 

a firm 60-day deadline is not workable 

in practice.803 Several opponents argue 

that the Commission’s proposed penalty 

regime is inconsistent with the new 

requirements the Commission has 

proposed for regional planning and 

requirements to consider redispatch in 

the system impact study.804 In its reply 

comments, EEI argues that due process 

requires that the Commission not 

impose penalties on transmission 

providers for study delays because, in 

EEI’s view, it is highly likely that the 

delays will have been caused by factors 

or events that were beyond the 

transmission provider’s control. 

Southern asserts that any scheme of 

operational penalties associated with 

the processing of studies cannot be 

implemented fairly unless and until the 

problem surrounding the submission of 

multiple requests is addressed. 

Southern argues that the Commission 

would violate a transmission provider’s 

due process rights if it were to impose 

penalties for delays caused by 

transmission customers. CREPC 

proposes that transmission projects that 

cross seams not be subject to penalties, 

arguing that such an exception will 

create a level playing field for those 

transmission providers in the West 

working with the CAISO and foreign 

transmission owners to resolve 

transmission service requests. 

1328. A number of commenters ask 

the Commission to clarify specific 

elements of the proposed operational 

penalty regime. Several commenters 

argue that the proposal does not clearly 

provide for an exemption from 

operational penalties if the failure to 

meet the timeliness criteria is a result of 

extenuating circumstances or customer 

caused delays, thereby denying 

transmission providers due process.805

Several commenters ask the 

Commission to clarify that a 

transmission provider is not subject to 

operational penalties if the transmission 

provider’s failure to meet the 

compliance threshold following its 

notification filing is due to extenuating 

circumstances.806 Southern asks that the 

Commission clarify that the submission 

of a notification of extenuating 

circumstances would suspend the 

obligation of a transmission provider to 

process at least 90 percent of the study 

requests within the proposed deadlines, 

until such time as the Commission 

issues a final determination on the 

notification of extenuating 

circumstances. Tacoma asks the 

Commission to ensure that the 

processing time is measured from the 

point that the customer provides 

complete information. 

1329. EEI recommends that the 

Commission hold a technical conference 

to determine the extent to which studies 

are not being completed within 60 days, 

the principal causes of delays in 

completing studies within 60 days and 

whether the increased planning and 

coordination requirements proposed by 

the Commission will result in additional 

time being needed to complete the 

studies. EEI believes the Commission is 

far more likely to arrive at a reasonable 

conclusion concerning these issues after 

a technical conference than if it simply 

imposes penalties for failures to 

complete all studies within 60 days. 

Seattle believes the proposed penalties 

should not be implemented until 

providers and customers have had at 

least one year of experience working 

with the performance metrics. 

1330. Transmission customers 

generally support the Commission’s 

proposal to impose operational 

penalties when a transmission provider 

routinely fails to meet the 60-day due 

diligence deadlines.807 In its reply 

comments, Entegra argues that the 

question is not whether a transmission 

provider has sufficient margins of 

flexibility, but whether the transmission 

provider has any stake in meeting the 

deadlines. Occidental argues that 

transmission providers may have little 

incentive to meaningfully address 

customers’ issues without the prospect 

of a prospective remedy. Responding to 

EEI’s due process argument, TDU 

Systems in reply assert that imposition 

of penalties in this instance raises no 

more due process concerns than those 

operational penalties that transmission 

customers are routinely subjected to 

under the OATT. TDU Systems argue 

that, should the Commission determine 

that transmission providers are entitled 

to challenge any operational penalty for 

failure to process service requests in a 

timely manner, then those challenges 

must be on terms and conditions that 

are comparable to those available to 

transmission customers—a complaint 

pursuant to FPA section 206. TDU 

Systems believe that the proposed 

‘‘explanatory statement’’

contemporaneous with any notification 

filing is a form of expedited review that 

is clearly not comparable to the 

treatment of customers under the tariff. 


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808E.g., TAPS, Constellation, and Entegra. 

809E.g., Bonneville, MidAmerican, Progress 

Energy, NorthWestern, Northwest IOUs, and EEI 

Reply. 

810E.g., MISO, MISO/PJM States, TDU Systems, 

and Indianapolis Power Reply. 

811E.g., Southern, TAPS, Progress Energy, Salt 

River, and Xcel. 

1331. Several transmission customers 

question whether the proposed penalty 

level is sufficient to ensure 

compliance.808 Constellation 

recommends a penalty of up to $10,000 

per day per violation. Entegra suggests 

the Commission set the penalty equal to 

the higher of the lost opportunity cost 

to the customer resulting from the delay, 

if any, or $1,000 for each day. Entegra 

also suggests that penalties should be 

assessed automatically, without a 

notification filing to the Commission. In 

its reply comments, EEI argues that the 

total penalty for delayed studies will be 

far higher than $500 per day if the 

transmission provider is processing 

more than five requests per 60-day 

period, which EEI asserts is extremely 

likely. 

1332. Constellation asks the 

Commission to consider whether to 

require the transmission provider to 

engage an independent transmission 

administrator to the extent a 

transmission provider’s posted 

performance metrics are not accurate or 

the transmission provider persistently 

fails to adhere to the relevant timelines. 

1333. Several commenters suggest 

that the Commission extend the study 

completion deadlines, such as to 120 or 

180 days, at least for the purposes of 

assessing penalties.809 Bonneville 

suggests that the Commission change 

the service request study process to 

match the interconnection study process 

as articulated in the Large Generator 

Interconnection Procedures. Imperial 

recommends that instead of mandating 

a nationwide study schedule, each of 

the NERC regions should establish a 

schedule taking into account the various 

needs of the region. Southern suggests 

restarting the 60-day due diligence 

period for any study that experiences a 

delay that cannot properly be attributed 

to the transmission provider. In contrast 

to the suggestions to increase the study 

time, Entegra suggests that the 

Commission consider changing the due 

diligence deadlines to 30 days to further 

the goal of encouraging timeliness in 

completing required studies. 

1334. Several commenters suggest 

methods for distributing the operational 

penalties the transmission provider pays 

for late studies. TAPS believes that 

penalty revenues should go to victims of 

study delay. Similarly, Entegra believes 

the penalty should take the form of a 

credit against the transmission 

customer’s obligation to reimburse the 

transmission provider for study costs, 

with any amount in excess of the study 

costs payable to the transmission 

customer, in recognition of the harm to 

transmission customers when required 

studies are not completed expeditiously. 

CREPC asks the Commission to clarify 

how it plans to determine which 

unaffiliated transmission customers will 

receive operational penalty payments. 

CREPC also asks the Commission 

whether the $500 per day penalty is a 

flat rate that would be pro-rated among 

eligible non-offending, unaffiliated 

transmission customers or if the $500 is 

a rate paid to each eligible transmission 

customer. 

1335. Commenters affiliated with 

RTOs and one transmission customer 

support the Commission’s proposal to 

exempt RTOs from penalties for late 

studies.810 MISO asserts that RTOs do 

not have incentives to delay the 

processing of transmission service 

requests, as they have no affiliates to 

favor and because their Commissionapproved design and internal 

procedures ensure their independence. 

MISO argues further that all 

transmission service requests benefit 

some RTO member and, as a result, 

RTOs have no disincentive to approve 

service so long as reliability is 

maintained. MISO/PJM States asserts 

that the NOPR proposal to exempt RTOs 

from operational penalties for late 

studies is appropriate because a penalty 

does not serve a useful purpose with 

respect to RTOs. TDU Systems state that 

an RTO should not be financially 

penalized for late studies because RTO 

independence should minimize 

incentives for affiliate preference and 

RTO members indirectly pay for all RTO 

incurred costs in any event. 

1336. Most of those commenters not 

affiliated with an RTO oppose the 

proposal to exempt RTOs from penalties 

for late studies.811 Southern argues that 

given that the Commission is seeking to 

increase transparency in the system, the 

Commission would undercut that goal 

by omitting a significant segment of the 

industry. TAPS argues that RTOs may 

still fail to complete studies on a timely 

basis due to competing internal 

priorities or bureaucratic indifference. 

Progress notes that the Commission has 

found that RTOs and ISOs should be 

subject to penalties for failure to meet 

reliability standards. Salt River argues 

that RTOs should be subject to 

operational penalties because the 

impact on the customer is identical if 

the request processing deadline is not 

met regardless of the type of provider 

conducting the study. Xcel notes that, 

historically, transmission owners need 

to complete facility studies in concert 

with RTOs, thereby giving the customer 

the most up-to-date and coordinated 

analysis. Consequently, Xcel believes it 

is imperative that both transmission 

owners and RTOs operate under the 

same rules, reporting obligations, and 

performance metrics in the OATT. 

1337. In its reply comments, WPS 

disagrees with the Commission’s 

proposal to exempt RTOs from penalties 

for their repeated failure to meet the 60- 

day due diligence requirements. WPS 

asserts that the Commission should 

impose penalties and prohibit the 

recovery of associated revenue where 

appropriate. WPS argues that RTO 

independence does not guarantee RTO 

competence or compliance in every 

instance. WPS believes imposing 

reporting obligations and penalties for 

failure to comply with tariff 

requirements, particularly tariff 

deadlines, will help to motivate 

compliance by ensuring that RTOs 

devote resources to tariff compliance. 

WPS acknowledges that a non-profit 

RTO has no dividends to cancel and 

likely no property to liquidate to cover 

these shortfalls, yet believes that such 

organizations can exercise cost-cutting 

measures, especially regarding rewards 

for employee performance, and thereby 

bear some financial responsibility and 

accountability for their operational 

violations. In the event of a penalty, 

WPS believes the Commission could 

require an RTO to take steps to cover its 

penalty-related revenue shortfall by 

cutting its budget, eliminating 

management bonuses and 

demonstrating that it has taken 

reasonable corrective steps before the 

Commission permits recovery of the 

remaining penalty revenue from its 

members and customers. To the extent 

some portion of an RTO’s penalties are 

passed through to its market 

participants, including transmission 

owners, WPS argues that those market 

participants would be in a position to 

take actions similar to the actions taken 

by shareholders of a publicly traded 

company to motivate the RTO either by 

changing the RTO’s processes or its 

Board of Directors. 

1338. TAPS states that some 

adaptation of the penalties may be 

necessary to make them appropriate and 

effective in the non-profit RTO/ISO 

context, for example, by requiring a 

reduction in management 

compensation. TDU Systems 

recommend that RTOs be subject to the 

notification filing requirement that is 

part of the Commission’s penalty 


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12440 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

812E.g., Duke, MidAmerican, and TranServ. 

proposal, regardless of whether RTOs 

are subject to pay penalties. TDU 

Systems believe this reporting 

requirement would provide an objective 

measure of RTO efficiency. APPA 

believes steps should be taken to 

remedy tardy RTO processing of service 

requests, suggesting that performance 

incentives for RTO employees, if 

carefully designed, could be useful. In 

its reply comments, Duke argues that 

although transmission owners in RTOs 

should not pay the price for RTOs 

failures to abide by the tariff, RTOs lack 

of performance should be addressed by 

the Commission, perhaps in a separate 

proceeding. 

1339. Transmission providers that 

have retained an independent tariff 

administrator suggest that these 

independent entities should also be 

exempt from operational penalties 

related to study completion times.812 In 

their view, these independent entities 

also have no incentive to discriminate 

when completing service request 

studies. Similarly, NorthWestern argues 

that a transmission provider without an 

affiliate that could benefit from a delay 

in completing service request studies 

also should be exempt from paying the 

proposed operational penalties. 

Commission Determination 

1340. The Commission adopts the 

NOPR proposal to subject transmission 

providers to operational penalties when 

they routinely fail to meet the 60-day 

due diligence deadlines prescribed in 

sections 19.3, 19.4, 32.3 and 32.4 of the 

pro forma OATT. Transmission 

providers must have a meaningful stake 

in meeting study time frames. As 

discussed above, a transmission 

provider will be required to make a 

notification filing with the Commission 

indicating that it has not completed 

request studies on a timely basis and 

may present evidence that extenuating 

circumstances prevented it from 

completing studies on a timely basis. 

The transmission provider then will be 

subject to an operational penalty if the 

transmission provider continues to be 

out of compliance with the deadlines 

prescribed in the pro forma OATT for 

each of the two quarters following its 

notification filing and the Commission 

determines that no extenuating 

circumstances exist to excuse the 

transmission provider’s noncompliance. The transmission provider 

will be deemed to be out of compliance 

if it completes 10 percent or more of 

non-affiliates’ system impact studies 

and facilities studies outside of the 

deadlines prescribed in the pro forma 

OATT. The operational penalty will be 

assessed on a quarterly basis, starting 

with the quarter following the 

notification filing and continuing until 

the transmission provider completes at 

least 90 percent of all studies within 60 

days after the study agreement has been 

executed. For any system impact study 

or facilities study completed during that 

quarter and more than 60 days after the 

study agreement was executed, the 

penalty will equal $500 for each day the 

transmission provider takes to complete 

the study beyond 60 days. For any 

system impact study or facilities study 

that is still pending at the end of the 

quarter and that has been in the study 

queue for more than 60 days, the 

penalty will equal $500 for each day the 

study has been in the study queue 

beyond 60 days. 

1341. The late study penalty regime 

described in this Final Rule will become 

effective at the same time as the rest of 

the new pro forma OATT. The penalty 

regime is designed so that the 

transmission provider has to be out of 

compliance for at least three quarters 

before it is subject to late study 

penalties. We believe nine months is 

sufficient time for the transmission 

provider to adjust its operations to the 

new requirements in this Final Rule, 

including penalties for late studies. That 

is, we believe transmission providers 

should be able to reallocate employees 

to study requests for service and hire 

new staff, to the extent these steps are 

necessary, by the time the transmission 

provider will be subject to civil 

penalties. 

1342. The procedures underlying the 

operational penalty regime adopted in 

this Final Rule ensure that the due 

process rights of transmission providers 

are protected. In their notification filing, 

transmission providers will have the 

right to document and describe any 

unique complexities that particular 

requests introduce into the study 

process and that prevent the 

transmission provider from completing 

the study within a the 60-day due 

diligence time frame. Thus the 60-day 

time frame will continue to be a flexible 

deadline, especially given that the 

transmission provider is not required to 

complete all studies within 60 days. 

These due process rights provide a de 

facto case-by-case review of the 

transmission provider’s efforts to 

complete studies on a timely basis. 

1343. On review of a notification 

filing, we will waive operational 

penalties if a transmission provider 

establishes that its non-compliance is 

the result of factors or events that are 

truly beyond its control, including 

delays caused by the transmission 

customer. We will not, however, exempt 

all transmission projects that cross 

seams from operational penalties, as 

CREPC urges. We will consider the 

specific facts surrounding studies of 

such projects based on a transmission 

provider’s notification filing. In 

response to TDU Systems, we 

acknowledge that the procedures for 

addressing a transmission provider’s 

failure to conform to the 60-day time 

frame are not the same as the 

procedures applicable to a transmission 

customer that is assessed an operational 

penalty under the pro forma OATT. We 

believe such different procedures are 

justified in this instance. The other 

operational penalties in the pro forma 

OATT are assessed for failure to remain 

in compliance with strict requirements, 

while the study time frame is based on 

the transmission provider using its due 

diligence to complete studies within 60 

days. The Commission recognizes that 

the transmission provider must have 

flexibility, within reason, to complete 

studies outside of this time frame. At 

the same time, the notification and 

penalty procedures we adopt in this 

Final Rule will ensure that this 

flexibility is not abused. 

1344. We do not find the remaining 

comments in opposition to the 

operational penalty for late studies to be 

compelling, particularly given the 

flexibility built into our penalty regime. 

We would not expect a transmission 

provider to prematurely deny a request 

for service simply to avoid an 

operational penalty. According to 

section 17.5 of the pro forma OATT, a 

transmission provider must either grant 

service or offer the transmission 

customer a system impact study. The 

transmission provider does not have the 

option to simply deny the request for 

service. We therefore interpret 

comments that the transmission 

provider may prematurely deny a 

request to mean that the transmission 

provider will not explore all possible 

system upgrades or redispatch options 

as required by section 19.3 of the pro 

forma OATT or any conditional firm 

options discussed in section V.D.1. 

Such behavior would be a tariff 

violation that should be brought to our 

attention. The transmission provider is 

required under the pro forma OATT to 

provide a complete study and 

corresponding work papers to the 

transmission customer. If a transmission 

customer feels a system impact study is 

incomplete, it has recourse to call the 

Commission’s Enforcement Hotline or 

file a formal complaint with the 

Commission. 

1345. We also do not expect a 

transmission provider to accept a 


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transmission service request to the 

detriment of system reliability simply to 

meet the study time frame. First, the 

transmission provider is not required to 

complete every request study within 60 

days. Second, to the extent our new 

requirements that the transmission 

provider consider conditional firm 

options and participate in regional 

planning cause study delays, the 

transmission provider can document 

and describe such delays in its 

notification filing. Finally, the 

transmission provider has been required 

to consider redispatch in the system 

impact study since Order No. 888 was 

issued, so the 60-day due diligence time 

frame should continue to be consistent 

with the long standing requirement to 

consider redispatch in the system 

impact study. 

1346. As we discuss below, we 

believe NAESB’s queue hoarding and 

queue flooding business practices, as 

well as additional reforms adopted in 

this Final Rule, will address the 

problem surrounding the submission of 

multiple requests. With regard to 

requests for a technical conference or 

further procedures to consider the effect 

of our operational penalty regime, we 

believe the commenters’ proposals 

would largely provide anecdotal 

information and speculation on the 

impacts of the new planning and 

coordination requirements. Our 

experience from the last ten years, and 

the comments provided in response to 

the NOI and NOPR, provide a sufficient 

basis to develop a penalty regime. In 

addition, the very requirement that 

transmission customers post 

performance metrics and submit 

notification filings prior to assessment 

of operational penalties will provide 

actual experience with the new regime. 

As explained above, the notification 

procedures adopted today will ensure 

that we will not assess a penalty for late 

studies unless justified by the 

circumstances. We can propose 

additional changes to the study process 

or penalty regime based on the actual 

experience under this Final Rule if our 

experience warrants it. 

1347. As described above, we adopt 

the proposal to set the operational 

penalty for late studies equal to $500 

per day per late study. We believe $500 

per day per late study is in line with the 

cost the transmission provider would 

incur to focus additional resources on 

processing requests studies. In addition, 

the penalty for being one month late, 

$15,000, is in line with the overall cost 

of the study. We conclude that the $500 

per day per late study penalty is high 

enough to provide the incentive to 

transmission providers to comply with 

study processing deadlines in the pro 

forma OATT, while not being 

unnecessarily punitive. We believe that 

a penalty in the range of $10,000 per 

day per late study would be 

unnecessarily punitive. The proposal to 

set the penalty equal to the higher of the 

lost opportunity cost to the customer 

resulting from the delay, if any, or 

$1,000 for each day is administratively 

cumbersome and could result in 

administrative costs that are not 

justified. Finally, we believe the due 

process afforded the transmission 

provider is an important element of the 

penalty regime, so we decline to impose 

penalties automatically, without a 

notification filing to the Commission. 

1348. As indicated in the NOPR, we 

may order other remedial actions in 

addition to the operational penalties 

described above, consistent with the 

Policy Statement on Enforcement. We 

will determine any other remedial 

action on a case-by-case basis. The 

decision to order other remedial actions 

will be based, among other things, on 

whether we believe the transmission 

provider is using the same due diligence 

to complete studies for non-affiliated 

customers as it uses to complete studies 

for itself. We do not believe it would be 

appropriate, as a general matter, to 

require a transmission provider to 

engage an independent transmission 

administrator to the extent its posted 

performance metrics are not accurate. 

As a threshold matter, Commission 

audit staff may audit the accuracy of a 

transmission provider’s posted metrics. 

If we are concerned about the accuracy 

of a transmission provider’s metrics, we 

will evaluate the use of third-party 

audits at that time. We will not prejudge 

which remedial actions we will 

consider if a transmission provider 

persistently fails to adhere to the 

relevant timelines. Rather, we will 

review each such instance on a case-bycase basis and determine the 

appropriate remedial action consistent 

with the Commission’s Policy Statement 

on Enforcement. 

1349. We clarify that a transmission 

provider is not subject to operational 

penalties if it can make a showing that 

its failure to meet the compliance 

threshold following its notification 

filing is due to extenuating 

circumstances, as we agree that the 

transmission provider should not be 

penalized for factors out of its control. 

The submission of a notification of 

extenuating circumstances will not, 

however, suspend the obligation of a 

transmission provider to process at least 

90 percent of the study requests within 

the proposed deadlines, until such time 

as the Commission issues a final 

determination on the notification of 

extenuating circumstances. At the same 

time, we will not require the 

transmission provider to distribute its 

operational penalty while we are still 

considering the transmission provider’s 

notification filing. The transmission 

provider nonetheless remains liable for 

paying the operational penalty for all 

request studies completed or 

outstanding after the notification filing 

and not completed within 60 days. This 

timing will balance the transmission 

provider’s due process rights with the 

need to provide an incentive to the 

transmission provider to complete 

studies on a timely basis. 

1350. We clarify that the processing 

time is measured from the point that the 

customer returns its executed study 

agreement to the transmission provider. 

By the time the transmission provider 

offers a system impact study agreement, 

it should have all the information it 

needs to complete the study. Pursuant 

to section 17.4 of the pro forma OATT, 

the transmission provider can deem a 

transmission service request deficient if 

the transmission customer does not 

provide all information the transmission 

provider needs to evaluate the request 

for service. We expect the transmission 

provider to use informal means to 

communicate the information it needs 

from the transmission customer before it 

deems a transmission service request 

deficient. 

1351. We adopt the NOPR proposal to 

have the transmission provider 

distribute the operational penalty for 

late studies to all non-affiliated 

transmission customers, as discussed in 

section V.C.5.b of this Final Rule. We 

believe that a transmission provider that 

is not processing studies on a timely 

basis potentially harms all transmission 

customers, not just those with requests 

in the study queue. For instance, a 

transmission customer may decide 

against requesting service that it 

believes will require a system impact 

study if the transmission provider is not 

processing transmission service requests 

on a timely basis. Therefore, we will not 

adopt suggestions to distribute penalty 

revenue only to transmission customers 

that have request studies that are not 

completed within 60 days. We clarify 

that the penalty is $500 per day per late 

study, with the resulting total penalty 

revenue distributed to unaffiliated 

transmission customers as discussed in 

section V.C.5.b of this Final Rule. We 

clarify that the transmission provider 

will propose a method to determine 

how unaffiliated transmission 

customers will receive operational 

penalty payments, as discussed in 

section V.C.5.b of this Final Rule. 


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813Rules Concerning Certification of the Electric 

Reliability Organization; and Procedures for the 

Establishment, Approval, and Enforcement of 

Electric Reliability Standards, Order No. 672–A, 71 

FR 19814 (Apr. 18, 2006), FERC Stats. & Regs. 

¶ 31,212 at P 56 (2006) (‘‘It is not arbitrary and 

capricious to treat all operators alike, including 

RTOs and ISOs, in terms of their liability for 

violation of a Reliability Standard.’’). 

814E.g., MidAmerican, MISO, Seattle, Southern, 

TranServ, TAPS, and CREPC. 

1352. We will not alter the 60-day 

study completion timeframe currently 

embodied in sections 19.3, 19.4, 32.3 

and 32.4 of the pro forma OATT. We 

continue to believe, absent concrete 

evidence to the contrary, that the 

existing timeframe adequately balances 

the need for expeditious resolution of 

request studies and the need to ensure 

that the transmission provider can 

reliably accommodate the transmission 

service reserved. Moreover, we believe 

the penalty regime defined in this Final 

Rule protects the transmission provider 

in the event studies take longer to 

complete due to the new planning 

requirements defined in section V.B of 

this Final Rule or the new requirement 

to consider conditional firm options as 

defined in section V.D.1 of this Final 

Rule. We will not adopt the suggestion 

to restart the 60-day due diligence 

period for any study that experiences a 

delay that can not properly be attributed 

to the transmission provider. We 

reiterate that the transmission provider 

is not subject to penalties for late 

studies if it can establish that delays are 

due to factors the transmission provider 

cannot control. 

1353. The Commission declines to 

adopt the NOPR proposal to exempt 

RTOs from operational penalties for 

completing studies on an untimely 

basis. We agree with those commenters 

that argue that RTO independence does 

not guarantee RTO competence or 

compliance in every instance and that 

RTOs may fail to complete studies on a 

timely basis due to competing internal 

priorities or staffing issues. Imposing 

penalties for failure to comply with the 

due diligence timeframe for completing 

studies will provide RTOs an 

appropriate incentive to comply with 

the pro forma OATT requirements and 

ensure that they devote adequate 

resources to tariff compliance. Finally, 

we note that subjecting RTOs to 

operational penalties for late studies is 

consistent with the Commission’s 

decision to subject RTOs and ISOs to 

penalties for failure to meet reliability 

standards.813 We believe that all 

transmission providers, including RTOs, 

should operate under the same rules, 

reporting obligations, and performance 

metrics in the OATT. We will 

nonetheless keep in mind the nature of 

an RTO’s operations and the RTO’s 

unique characteristics when we 

consider whether penalties would be 

appropriate. We agree that RTOs do not 

have an incentive to discriminate 

(which is one of the bases for this 

policy) and we agree that imposing a 

penalty raises the issue of cost recovery, 

as most RTOs are not-for-profit entities. 

We will therefore consider these and all 

other relevant factors in exercising our 

discretion whether to impose a penalty 

in a given circumstance. 

1354. Consistent with the treatment of 

RTOs, we will not exempt independent 

entities that provide tariff 

administration from penalties for late 

completion of studies. As with RTOs, 

independence does not guarantee 

competence or compliance in every 

instance. Independent entities have a 

similar incentive to limit the personnel 

committed to processing request studies 

in an effort to reduce overhead costs. 

We believe that all entities 

administering the tariff should operate 

under the same rules, reporting 

obligations, and performance metrics in 

the pro forma OATT. 

(3) Recovery Through Rates 

NOPR Proposal 

1355. The Commission proposed that 

a transmission provider cannot recover 

for ratemaking purposes any operational 

penalty it pays for failing to process 

transmission service studies on a timely 

basis. 

Comments 

1356. CREPC noted that, while it may 

be reasonable for an investor-owned 

utility to pay penalties without being 

allowed to recover the penalties in rates, 

this approach will be problematic for 

utilities that do not have shareholders. 

Commission Determination 

1357. We will prohibit all 

jurisdictional transmission providers 

from recovering penalties for late 

studies from transmission customers. 

We believe that all entities 

administering the tariff should operate 

under the same rules, reporting 

obligations, and performance metrics in 

the pro forma OATT. Non-profit 

transmission providers have other 

sources of money to pay penalties 

beyond the revenue they collect for 

sales of transmission service. Therefore, 

we require non-profit transmission 

providers to pay operational penalties 

for late studies from their other sources 

of money. This notwithstanding, we 

may consider factors such as an entity’s 

financial ability to absorb a penalty in 

determining whether to impose 

penalties in the first instance. 

(4) Fee for Multiple Self-Competing 

Transactions 

NOPR Proposal 

1358. In the NOPR, the Commission 

sought comment on a fee structure that 

could provide a disincentive for 

transmission customers to submit 

duplicative requests without penalizing 

transmission customers that have 

legitimate requests for transmission 

service. The Commission asked for 

detailed recommendations, including 

any proposed tariff language, regarding 

the standards it should use to identify 

requests that would be subject to a fee. 

The Commission also sought 

recommendations on the level of a fee 

that balances its policy goals to 

discourage requests for transmission 

service that the transmission customer 

does not intend to confirm while not 

discouraging legitimate requests for 

transmission service. Finally, the 

Commission sought comment regarding 

the circumstances, if any, under which 

the processing fee would be refunded to 

or credited to the transmission 

customer. 

Comments 

1359. A number of commenters 

express support for a fee for duplicative 

requests.814 CREPC believes that queue 

blocking behavior should be 

discouraged so that legitimate requests 

lower in the queue are not 

disadvantaged. MISO believes the 

transmission provider should be 

allowed to charge a fee that is small 

enough to not create a barrier to entry 

yet high enough to ‘‘add up’’ for anyone 

wishing to flood the queue. MISO and 

Seattle suggest that the fee be based on 

the transmission provider’s cost to 

review a request and handle the initial 

processing. MISO also believes the 

transmission provider should be able to 

charge a fixed dollar amount for any 

accepted requests that the customer 

wants to retract. Southern suggests that 

the Commission consider a procedure 

whereby transmission customers place a 

deposit with transmission providers to 

cover a certain number of requests that 

is forfeited once the requests reach a 

certain threshold and are deemed selfcompeting. TranServ suggests that the 

fee apply to requests for long-term firm 

transmission service and be based on 

duration of the request and not capacity 

requested as an incentive to the 

transmission customer to submit fewer 

combined requests where possible. 

TranServ suggests this fee could be 


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815E.g., EEI, Nevada Companies, Powerex, and 

Suez Energy NA. 

816E.g., EEI, Powerex, Suez Energy NA, and 

Entegra. 

817E.g., EEI and TAPS. 

818See Midwest Independent Transmission 

System Operator, Inc., 97 FERC ¶ 61,269 (2001) 

(rejecting a proposal to include a fee for nonconfirmed transmission service requests for firm 

point-to-point transmission service of one week or 

longer). 819E.g., CREPC, Powerex, and Suez Energy NA. 

waived if the service request is 

submitted pre-confirmed. 

1360. Most of the transmission 

customers and some transmission 

providers oppose the creation of a fee 

structure for duplicative requests for 

transmission service.815 Several 

commenters argue that the Commission 

should determine whether the newlyadopted NAESB business practices and 

other reforms proposed in the NOPR can 

reduce the number of requests that the 

transmission customer does not intend 

to confirm.816 Nevada Companies and 

Great Northern assert that the current 

deposit requirement serves to 

discourage multiple self-competing 

requests. Constellation asserts that the 

Commission should focus on narrowlytailored penalties to deter market 

participants from intentionally jamming 

the queue. 

1361. Several commenters suggest 

that a transmission provider that makes 

a showing that it is experiencing a 

significant problem with respect to 

customers’ submission of multiple 

competing requests should be allowed 

to propose a fee to combat the 

problem.817 MISO notes that the 

Commission has rejected a fee for 

unconfirmed requests in the past.818

1362. TAPS believes the fee revenue 

should be shared with network 

customers on a load-ratio share basis. 

TAPS also suggests that the fee apply to 

the transmission provider’s merchant 

arm in a meaningful way. 

1363. CREPC urges the Commission to 

adopt a simple, straightforward standard 

for determining duplicative requests, 

such as the same points of receipt and 

delivery, same source and sink, same 

time frame, and same firmness, as well 

as the same project at multiple 

locations. Powerex recommends that the 

Commission be very specific in 

describing the types of multiple 

transmission requests it believes to be a 

problem and the fee structure that 

would be applied to such problematic 

requests. For example, Powerex believes 

the Commission should clarify that 

requests subject to the fee must be 

multiple, not pre-confirmed, and with 

identical quantity, point of receipt, 

point of delivery, start time, end time, 

and firmness. In its reply comments, 

Santa Clara disagrees with Powerex. 

Santa Clara urges the Commission to 

examine the practice of queue hoarding 

and punish those entities that are acting 

in an anticompetitive and manipulative 

manner. Further, Santa Clara urges the 

Commission to refrain from being too 

specific in its ruling, as a more general 

explanation of the behavior to be 

avoided would go a long way in 

preventing entities from making an endrun around a ruling against queue 

hoarding. 

1364. MidAmerican believes that if a 

fee is imposed, the fee should not be 

refunded as the administrative costs and 

difficulty of administering the refunds 

would be an unreasonable burden on 

the transmission provider. CREPC 

believes refunding or crediting the 

processing fee would defeat the purpose 

of having one in the first place, although 

the processing fee could be refunded if 

the duplicative service request attached 

to it actually comes to fruition. Suez 

Energy NA suggests that the processing 

fee be refunded whenever the 

transmission provider exceeds the 60- 

day request study due diligence 

deadline. TAPS suggests that the fee be 

structured to provide for exceptions 

where the failure to confirm reflects a 

legitimate purpose, not jamming. TAPS 

cites as examples transmission requests 

associated with requests for proposals, 

alternative sites for planned generation, 

and the inability to secure timely 

confirmation of all legs of a multisystem path. TAPS notes that the 

current pro forma OATT accommodates 

multiple submissions in relation to the 

same competitive solicitation in 

sections 19.2(ii) and 32.2(ii). 

Commission Determination 

1365. The Commission will not 

require transmission providers to charge 

a fee for duplicative requests for 

transmission service. We will instead 

first consider whether the newly 

adopted NAESB queue flooding and 

queue hoarding business practices 

reduce the number of requests that the 

transmission customer does not intend 

to confirm. We are concerned that 

benefits to market participants would 

not justify the administrative costs of a 

new fee if the NAESB business practices 

can effectively discourage transmission 

service requests the transmission 

customer does not intend to confirm. 

We also believe that the current deposit 

mechanism in section 17.3 of the pro 

forma OATT should have the same 

effect as a fee based on the transmission 

provider’s cost to process the request for 

transmission service, like the fee MISO 

and CREPC propose. Pursuant to section 

17.3, in the event a transmission 

customer retracts or withdraws a 

request, the transmission provider is 

allowed to deduct from the transmission 

customer’s deposit the costs the 

transmission provider incurred to 

process the request. As a result, we do 

not believe any other fee structure is 

necessary to make the transmission 

provider whole when a transmission 

customer submits a transmission service 

request it does not expect to confirm. 

1366. A transmission provider that 

continues to experience problems 

related to submission of multiple 

duplicative requests for transmission 

service is free to file a tariff modification 

that includes a fee to combat the 

problem. This filing should explain why 

the transmission provider is unable to 

handle the submission of multiple 

duplicative requests for transmission 

service through NAESB’s queue 

hoarding and queue flooding business 

practices. 

(5) Clustering Transmission Service 

Request Studies 

NOPR Proposal 

1367. In the NOPR, the Commission 

sought comment regarding whether a 

transmission provider should be 

required to study requests for 

transmission service in a group if the 

transmission provider fails to complete 

studies on a timely basis. If so, the 

Commission sought comment on the 

circumstances that should trigger such a 

requirement and the appropriate 

method of implementing the 

requirement. The Commission sought 

further comment regarding whether 

transmission providers should be 

required to study requests for 

transmission service in a group if all the 

transmission customers in the group 

agree to cluster their requests. Finally, 

the Commission sought comment 

regarding how to select the requests that 

belong to a cluster so that transmission 

customers cannot ‘‘cherry-pick’’ clusters 

to avoid transmission system upgrade 

costs. 

Comments 

1368. A few commenters, primarily 

transmission customers, believe 

transmission providers should be 

required to study requests for 

transmission service in a group.819

CREPC believes transmission providers 

should have the discretion to develop 

the criteria for clustering so that 

transmission customers do not have the 

opportunity to ‘‘cherry pick’’ study 

clusters. If transmission providers are 

required to study requests in a group, 

Powerex believes customers should be 


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820E.g., Bonneville, EEI, MISO, Nevada 

Companies, Southern, Entegra, and PNM–TNMP. 821E.g., NRECA, TDU Systems, and Seattle. 

given the option of paying the 

transmission provider to perform an 

individual study. Suez Energy NA 

believes studying requests that are 

clustered voluntarily will partially 

incorporate the value of counterflows in 

the study process. PGP believes 

transmission customers should have the 

opportunity to join a cluster, but only if 

the customer is bound to accept the 

study results. 

1369. A number of commenters, 

primarily transmission providers, state 

that transmission providers should be 

allowed, but not required, to study 

requests for transmission service in a 

group.820 Bonneville argues that the 

transmission provider is in the best 

position to determine whether requests 

should be studied individually or in 

groups. EEI asserts that clustering does 

not necessarily ensure timely 

completion of transmission studies. 

FirstEnergy believes each transmission 

service request should stand on its own 

merits and be directly assigned costs 

associated with its own request so that 

requests in one part of the request queue 

do not end up subsidizing requests in 

another part of the request queue. MISO 

believes giving the transmission 

provider discretion to cluster requests 

will address the Commission’s concerns 

with respect to transmission customers 

cherry-picking clusters to avoid paying 

upgrade costs. Arkansas Commission 

and East Texas Cooperatives suggest 

that the Commission allow clustering 

through an open season procedure 

similar to the procedure SPP currently 

uses pursuant to Attachment Z of SPP’s 

OATT. 

Commission Determination 

1370. The Commission will not 

require transmission providers to study 

transmission requests in a cluster, 

although we encourage transmission 

providers to cluster request studies 

when it is reasonable. We do, however, 

require transmission providers to 

consider clustering studies if the 

customers involved request the cluster 

and the transmission provider can 

reasonably accommodate the request. 

We believe clustering request studies 

offers potential benefits as the needed 

transmission upgrades are frequently 

large enough that the upgrade can 

accommodate more than one 

transmission service request. In 

addition, jointly modeling transmission 

service requests can allow the 

transmission provider to more 

efficiently design transmission system 

upgrades. Clustering also allows the 

transmission provider to include, to the 

extent it is consistent with good utility 

practice, the potential counterflows 

created by the clustered requests. We do 

not agree, as suggested by commenters, 

that clustering necessarily leads to one 

set of transmission customers 

subsidizing another set of transmission 

customers. 

1371. We therefore require each 

transmission provider to include tariff 

language in its compliance filing that 

describes how it will process a request 

to cluster request studies and how it 

will structure the transmission 

customers’ obligations when they have 

joined a cluster. We will give the 

transmission provider discretion to 

determine whether a transmission 

customer can opt out of a cluster and 

request an individual study. We are 

giving each transmission provider 

discretion to develop the clustering 

procedures it will use because we 

believe the transmission provider is in 

the best position to determine the 

clustering procedures that it can 

accommodate. We also believe that the 

transmission provider is in the best 

position to develop a clustering 

procedure that prevents a transmission 

customer from strategically selecting the 

clusters in which it participates in an 

attempt to avoid responsibility for 

needed transmission system upgrades. 

(6) Standardization of Business 

Practices for Study Queue Processing 

NOPR Proposal 

1372. In the NOPR, the Commission 

sought comment on whether additional 

standardization of request queue 

processing is necessary. If so, the 

Commission sought comment on the 

specific issues commenters believe are 

not clearly prescribed in Order No. 676 

or the NOPR and that require additional 

mandatory queue processing business 

practices. 

Comments 

1373. Several commenters identified 

issues where a transmission customer 

needs coordinated responses across 

several transmission systems in order to 

serve its load.821 Seattle and NRECA 

suggest that the Commission amend the 

pro forma OATT so that a customer’s 

applications for service across multiple 

systems that are intended to serve a 

single sink from an identified resource 

will be considered a single application 

for purposes of establishing the 

deadlines for rendering an agreement for 

service, revising queue status, eliciting 

deposits and finally commencing 

service. Seattle believes the Commission 

should permit coordination and 

implementation of these requirements 

by a third party such as wesTTrans.net 

and sub-regional planning 

organizations. At a minimum, these 

commenters ask the Commission to 

develop business practices to protect a 

transmission customer caught between 

two systems with uncoordinated 

deadlines. 

1374. Exelon states that the 

Commission should require all 

transmission providers to allow 

transmission customers to link 

consecutive requests for service (e.g., 

monthly firm service requests for 

December, January and February) and to 

evaluate such request as a single 

request. Exelon argues that this service, 

which is currently provided by some 

transmission providers, would increase 

uniformity and use of the transmission 

system, and enhance competitiveness 

without burdening transmission 

providers or adding administrative 

complexity. 

1375. TDU Systems indicate that 

several of its members have experienced 

difficulty related to the lack of 

standardized business practices, 

particularly in practices related to 

timing, application requirements, and 

requirements relating to methods of 

proving that a network customer has 

executed a power purchase agreement 

prior to designating the power purchase 

agreement as a network resource. 

1376. PNM–TNMP does not believe 

that additional clarity or business 

practices are necessary beyond those 

already provided in Order No. 676. 

However, to the extent additional issues 

arise, PNM–TNMP believes NAESB’s 

WEQ forum is the appropriate place to 

address them. Similarly, NorthWestern 

recommends that transmission 

providers work together within regional 

groups to develop a common set of 

business practices that will be followed 

by all transmission providers within 

each region, instead of the Commission 

using the NOPR comments it receives to 

develop a prescriptive set of business 

practices by which all transmission 

providers must abide. In its reply 

comments, Powerex argues that either 

the entire transmission process has to be 

integrated via an RTO, or coordination 

of requests across multiple control areas 

has to be done transmission provider by 

transmission provider. Powerex suggests 

that NorthWestern’s suggestion for 

regional development of business 

practices may be a more pragmatic 

approach to address concerns about 

coordination of requests across multiple 

systems. 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12445 

Commission Determination 

1377. The Commission agrees that 

transmission requests across multiple 

transmission systems should be 

coordinated by the relevant 

transmission providers. We will not, 

however, amend the pro forma OATT to 

require such coordination. Rather, we 

require transmission providers working 

through NAESB to develop business 

practice standards related to 

coordination of requests across multiple 

transmission systems. In order to 

provide guidance to NAESB, we will 

articulate the principles that should 

govern processing across multiple 

systems. All the transmission providers 

involved in a request across multiple 

systems should consider a request that 

requires studies across multiple systems 

to be a single application for purposes 

of establishing the deadlines for 

rendering an agreement for service, 

revising queue status, eliciting deposits 

and commencing service. In order to 

preserve the rights of other transmission 

customers with studies in the queue, the 

priority for the single application 

should be based on the latest priority 

across the transmission providers 

involved in the multiple system request. 

We note that regional entities like 

wesTTrans are already coordinating 

requests across multiple transmission 

systems and we believe such 

coordination is an acceptable solution to 

this issue. 

1378. We interpret Exelon’s request 

that we require all transmission 

providers to allow transmission 

customers to link consecutive requests 

for firm point-to-point transmission 

service and to evaluate such requests as 

a single request as asking us to (1) allow 

transmission customers to require the 

transmission provider to either grant 

service for the entire period, deny 

service for the entire period, or offer the 

same partial quantity for the entire 

period and (2) require the transmission 

provider to consider the full duration of 

the linked requests when determining 

reservation priority pursuant to sections 

13.2 of the pro forma OATT (short-term 

firm point-to-point transmission 

service). We require transmission 

providers working through NAESB to 

develop business practice standards to 

allow a transmission customer to rebid 

a counteroffer of partial service so the 

transmission customer is allowed to 

take the same quantity of service across 

all linked transmission service requests. 

Transmission providers need not 

implement these business practice 

standards until NAESB develops 

appropriate standards. We note that the 

transmission customer should not be 

required to take the same quantity of 

service across consecutive transmission 

service requests, it should simply have 

the option to do so. On the second issue, 

we reiterate that, according to existing 

NAESB business practice standard 001–

4.16, the transmission provider is 

required to consider the full duration of 

the linked requests when determining 

reservation priority pursuant to section 

13.2 of the pro forma OATT. 

1379. We believe most of the 

standardization issues TDU Systems 

raise (application requirements, 

requirements relating to methods of 

proving that a network customer has 

executed a power purchase agreement 

prior to designating the power purchase 

agreement as a network resource, and 

timing) have been addressed in this 

Final Rule. In particular, we describe 

the information a network customer is 

required to provide when designating a 

new network resource in section V.D.6.b 

of this Final Rule. We also indicate in 

section V.D.6.b that the transmission 

provider is not allowed to require a 

network customer to provide contract 

terms and conditions when it designates 

a power purchase agreement as a 

network resource. The network 

customer is required to provide a 

statement that attests, among other 

things, that it has executed a power 

purchase agreement prior to confirming 

its request to designate a new network 

resource. We will continue to give 

transmission providers discretion in 

determining whether to impose 

restrictions on the earliest time at which 

it will accept a request for transmission 

service. We believe the transmission 

provider is in the best position to 

determine whether it needs to restrict 

the time at which it will accept requests 

for transmission service in order to 

process transmission service requests in 

an orderly fashion consistent with the 

requirements in the pro forma OATT. 

(7) Additional Processing Proposals 

Comments 

1380. A number of commenters 

propose changes to queue processing 

requirements that were not addressed in 

the NOPR. 

1381. Powerex believes that OASIS 

practices should be modified to ensure 

that short-term firm and non-firm pointto-point service requests are processed 

based on the ATC posted at the time the 

requests were queued. Powerex argues 

that a transmission provider should not 

be permitted to grant transmission 

service requests at a time when its 

OASIS indicates there is no ATC. In its 

view, any such requests should be 

automatically denied. Powerex also 

suggests that confirmation time periods 

be shortened for short-term firm pointto-point service requests to discourage 

behaviors that have the effect of 

delaying queue processing. In its reply 

comments, Powerex asserts that 

requiring transmission provider 

responses to be based on posted ATC, as 

well as increasing standardization in 

transmission provider response time for 

short-term transmission requests, would 

enhance a transmission customer’s 

ability to manage multiple transmission 

provider requests within the context of 

the pro forma tariff. 

1382. Occidental suggests in reply 

that the Commission should introduce 

meaningful tariff-based sanctions for 

unauthorized deviations from the 

standards and modeling assumptions it 

proposes to include in Attachment C of 

the pro forma OATT, the transmission 

provider’s description of its ATC 

calculation methodology. 

1383. Several commenters make 

suggestions to allow the transmission 

provider to terminate idle transmission 

service requests. TDU Systems 

recommends that the Commission 

provide a sunset date by which all 

requests not pursued by the 

transmission customer would be 

terminated. MidAmerican and 

Northwest IOUs ask the Commission to 

clarify in the Final Rule that the 

transmission provider may deem a 

transmission service application 

withdrawn and terminated if a customer 

revises its application or if such 

customer fails to timely pay the annual 

reservation fee pursuant to section 17.7 

of the pro forma OATT. 

1384. Constellation asks the 

Commission to require transmission 

providers to release study results as 

soon as a study is completed, rather 

than holding them until the end of the 

60 days. 

1385. NorthWestern believes an 

appropriate modification to the study 

process would be to allow the 

transmission provider to have an 

opportunity to verify and correct the 

system impact study results at the 

beginning of the facilities study and 

again before construction begins. 

1386. With the exception of very 

short-term transmission service (for 

which a bid-based system is impractical 

to manage), LDWP suggests that the 

queue process be transformed into a 

competitive process in which awards of 

transmission service are allocated in a 

manner similar to the provisions in 

section 4.4 of Order No. 638. 

1387. TranServ notes that OASIS 

standards allow the customer to turn a 

request into a pre-confirmed request, 

but not vice versa. If the Commission’s 


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12446 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

822See, e.g., Florida Power Corp., 111 FERC ¶

61,243 at P 5 (2005). 

823 18 CFR 37.6(g)(4). 

proposal on granting priority to preconfirmed requests is adopted, TranServ 

believes this capability should be 

removed from OASIS as it would seem 

to invite gaming and confuse 

transmission providers attempting to 

process requests in proper queue order. 

1388. PGP states that OASIS platforms 

should be accessible from different 

computer platforms using a variety of 

browsers, not just one operating system/ 

browser combination (Windows/ 

Explorer), which is currently the case. 

Commission Determination 

1389. We will not adopt Powerex’s 

proposal to require the transmission 

provider to accept or deny in all cases 

non-firm and short-term firm point-topoint transmission service requests 

solely based on posted ATC. The issue 

Powerex raises is ultimately a question 

of how the transmission provider is 

going to exercise its discretion under the 

tariff. Under the pro forma OATT, the 

transmission provider can use its 

knowledge of the system to exercise its 

discretion to offer transmission service 

even if posted ATC is not sufficient to 

accommodate the requested service. 

Alternatively, the transmission provider 

can use its discretion to update posted 

ATC in response to a transmission 

customer’s verbal request to update 

ATC.822 In both situations, the 

transmission provider may provide 

transmission service in instances when 

posted ATC is not sufficient to 

accommodate a transmission service 

request at the time the transmission 

customer requests service. We do not 

wish to discourage transmission 

providers from making transmission 

service available at times when posted 

ATC is not accurate. Therefore, we will 

continue to allow the transmission 

provider to accept transmission service 

requests in instances when posted ATC 

is not sufficient but the transmission 

provider believes it can accommodate 

the service. The transmission provider 

must use its discretion to grant service 

when posted ATC is not sufficient on a 

non-discriminatory basis. In order to 

ensure that it does so, we expect the 

transmission provider to log such 

instances as an act of discretion and 

post the log as required in section 

37.6(g)(4) of the Commission’s 

regulations.823

1390. We will not modify the pro 

forma OATT to address requests to 

allow the transmission provider to 

terminate idle transmission service 

requests. NAESB’s business practice 

001–4.11 allows the transmission 

provider to retract a request if the 

transmission customer does not respond 

to an acceptance within the time 

established in NAESB business practice 

standard 001–4.13. Therefore, we 

interpret TDU Systems comments to 

refer to circumstances when a 

transmission customer fails to respond 

to the transmission provider’s request 

for additional information during the 

course of a request study. As discussed 

above, by the time the transmission 

provider offers a system impact study 

agreement, it should have all of the 

information that it needs to complete 

the study. Pursuant to section 17.4 of 

the pro forma OATT, the transmission 

provider can deem a transmission 

service request deficient if the 

transmission customer does not provide 

all of the information the transmission 

provider needs to evaluate the request 

for service. We will revise section 17.7 

of the pro forma OATT so that the 

transmission provider is able to 

terminate a request for transmission 

service if a transmission customer that 

is extending the commencement of 

service does not pay the required annual 

reservation fee within 15 days of 

notifying the transmission provider that 

it would like to extend the 

commencement of service. We will not 

change the pro forma OATT to allow the 

transmission provider to terminate a 

transmission service request if the 

transmission customer changes its 

application for service. We believe the 

existing pro forma OATT is sufficient to 

allow a transmission provider to manage 

situations where the transmission 

customer modifies its application for 

service to the point that the customer is 

requesting transmission service that is 

meaningfully different than its initial 

request. 

1391. We clarify that sections 19.3 

and 32.3 of the pro forma OATT require 

the transmission provider to release 

study results as soon as a study is 

completed, rather than holding them 

until the end of the 60 days. 

1392. Commenters also suggest 

changes to the OASIS protocols, 

including prohibiting transmission 

customers from changing a request into 

a pre-confirmed request and requiring 

OASIS platforms to be accessible on 

non-Windows/Explorer computers. We 

believe these issues are best addressed 

by NAESB. 

1393. Commenters proposed a 

number of additional modifications to 

the pro forma OATT that we do not 

believe are necessary. These proposals 

would (1) allow the transmission 

provider to verify and correct studies 

between each step in the study process, 

(2) transform the queue process into 

competitive process, (3) shorten the 

confirmation time periods for short-term 

firm point-to-point service requests and 

(4) introduce penalties when the 

transmission provider deviates from the 

ATC calculation procedures detailed in 

Attachment C of the pro forma OATT. 

We believe the pro forma tariff is just 

and reasonable without such 

modifications and the commenters have 

not demonstrated that reforms in these 

areas are required at this time to prevent 

the exercise of undue discrimination. 

b. Reservation Priority 

1394. Section 13.2 of the pro forma 

OATT requires transmission providers 

to process requests for long-term firm 

point-to-point service on a first-come, 

first-served basis and to process requests 

for short-term firm point-to-point 

service on a first-come, first-served basis 

conditional on the duration of the 

request. Section 14.2 of the pro forma 

OATT requires transmission providers 

to process requests for non-firm pointto-point service on a first-come, firstserved basis conditional on the duration 

of the request to the extent transmission 

capacity beyond that needed by native 

load customers, network customers and 

firm point-to-point transmission 

customers is available. In the NOPR, the 

Commission made a number of 

proposals and requested comment 

regarding various aspects of the 

reservation priority rules. 

(1) Priority for Pre-confirmed Requests 

NOPR Proposal 

1395. In the NOPR, the Commission 

proposed to change the priority rules to 

give priority to pre-confirmed requests 

for firm point-to-point transmission 

service. Specifically, the Commission 

proposed that a pre-confirmed shortterm request for firm transmission 

service would preempt any non-preconfirmed short-term requests, 

regardless of duration. Similarly, the 

Commission proposed that a preconfirmed request for long-term firm 

transmission service would preempt a 

request for long-term transmission 

service that is not pre-confirmed. Under 

the Commission’s proposal, a preconfirmed request for short-term 

transmission service would not preempt a non-pre-confirmed request for 

long-term transmission service. 

Comments 

1396. A number of commenters 

generally support the Commission’s 

proposal to give priority to preVerDate Aug<31>2005 18:17 Mar 14, 2007 Jkt 211001 PO 00000 Frm 00182 Fmt 4701 Sfmt 4700 E:\FR\FM\15MRR2.SGM 15MRR2

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824E.g., Nevada Companies, Seattle, LDWP, PGP, 

PNM–TNMP, Salt River, and Suez Energy NA. 825E.g., Ameren, Santa Clara, Entegra, Entergy, 

and TVA. 826E.g., Ameren and NorthWestern. 

827E.g., CREPC and EEI. 

828E.g., Entergy, Southern, and NorthWestern. 

829E.g., Bonneville and EEI. 

830E.g., Bonneville, EEI, and MidAmerican. 

831E.g., EEI, MISO, TAPS, Constellation, and 

TDU Systems. 

832Open Access Same-Time Information System 

and Standards of Conduct, Order No. 638, 65 FR 

17370, FERC Stats. & Regs., ¶ 1996–2000 ¶ 31,093 

at 31,439 (2000). 

833E.g., MidAmerican and TranServ. 

confirmed requests.824 Commenters who 

support the proposal note that giving 

reservation priority to pre-confirmed 

requests for transmission service could 

help alleviate the problems that arise 

when a transmission customer submits 

multiple identical requests for service 

with no intention of confirming all 

accepted requests.825 Supporters of the 

proposal also note that the proposal 

would allow the transmission provider 

to focus its attention on those requests 

that appear most likely to result in an 

actual reservation of transmission 

service.826 Although Nevada Companies 

do not oppose the proposal, they note 

that concerns regarding withdrawal of 

pre-confirmed requests might otherwise 

be alleviated by requiring a nonrefundable deposit on requests. 

1397. Several commenters suggest 

that establishing reservation priority 

first based on pre-confirmation status 

and then based on duration would 

ultimately result in transmission 

customers with relatively shorter term 

requests getting transmission service 

instead of transmission customers with 

relatively longer term requests.827 EEI 

asserts that this result would be 

inconsistent with the Commission’s 

desire to promote longer-term uses of 

the transmission system. Several 

transmission providers suggest that the 

Commission modify its proposal to 

ensure that longer duration requests 

continue to have a priority over shorter 

duration requests.828 EEI suggests that 

the Commission should use preconfirmation as a tie-breaker for shortterm requests for transmission service 

with the same duration. Southern argues 

further that a pre-confirmed daily or 

hourly request should not preempt a 

weekly request that has not been preconfirmed. 

1398. Opponents of the proposal 

identify a number of operational 

difficulties in implementing a system 

that gives priority to pre-confirmed 

requests. Several commenters note that 

transmission customers are not bound to 

take service because they pre-confirm a 

request for transmission service.829

They argue, for instance, a transmission 

customer is not bound to take service in 

the event the transmission provider 

offers a study or counteroffers the 

request with a partial quantity of 

service. Similarly, MidAmerican notes 

that a transmission customer may 

withdraw a pre-confirmed request for 

transmission service at any time prior to 

acceptance by a transmission provider. 

Opponents also argue that giving 

priority to pre-confirmed requests 

would disrupt the study process.830

This disruption would occur when a 

transmission provider receives a preconfirmed request for transmission 

service while it is actively studying a 

request for service that has not been preconfirmed. Under these circumstances, 

the transmission provider would be 

required to suspend the study of one 

request in order to study a request with 

a higher reservation priority. In its reply 

comments, Indianapolis Power asks the 

Commission to clarify if this 

interpretation of the NOPR proposal is 

accurate. TranServ, suggesting that the 

Commission has not proposed to give a 

priority to pre-confirmed requests for 

non-firm transmission service, asserts 

that having different priority rules for 

firm and non-firm transmission service 

introduces unnecessary complexity. 

Finally, Southern believes that a preconfirmed service request submitted 

within close proximity to the actual 

commencement of service should not 

preempt an existing non-pre-confirmed 

request, if doing so would be disruptive 

to the operations of the transmission 

provider or to the reliability of the 

system itself. 

1399. Opponents also argue that 

giving a priority to pre-confirmed 

requests would unfairly disadvantage 

transmission customers who are not in 

a position to pre-confirm their requests, 

such as those requesting service in 

response to a request for proposals.831

EEI notes that the Commission 

addressed this issue when it issued 

Order No. 638 and decided that giving 

priority to pre-confirmed requests 

would disadvantage customers who are 

requesting service from multiple 

transmission providers.832 In the event 

the Commission decides to proceed 

with its proposal, TAPS suggests that 

the Commission limit the priority for 

pre-confirmed requests to non-firm and 

short-term firm requests for 

transmission service. 

1400. Several commenters question 

whether a request that has been 

accepted but not confirmed would be 

pre-empted by a new pre-confirmed 

request.833 In a similar vein, TDU 

Systems suggests that the Commission 

include a time window between 

acceptance of a request and 

confirmation of the request, during 

which a request can not be preempted 

by a pre-confirmed request for 

transmission service. 

Commission Determination 

1401. The Commission generally 

agrees with those commenters that argue 

that giving a priority to pre-confirmed 

requests can increase the efficient 

utilization of the system by giving 

priority to customers who are 

committed to purchase service over 

those who have not so committed, 

including customers that submit 

multiple requests without any intent to 

take service if each request is granted. 

However, we are mindful of concerns 

that doing so could undermine the 

Commission’s desire to promote longerterm uses of the transmission system, 

disrupt the study process, or 

disadvantage transmission customers 

that are not in the position to preconfirm their requests. As a result, we 

will modify the NOPR proposal and give 

priority only to pre-confirmed non-firm 

point-to-point transmission service 

requests and short-term firm point-topoint transmission service requests. In 

addition, longer duration requests for 

transmission service will continue to 

have priority over shorter duration 

requests for transmission service, with 

pre-confirmation serving as a tie-breaker 

for requests of equal duration. This 

policy will still give an advantage to 

pre-confirmed requests without 

imposing substantial implementation 

difficulties or undermining the 

Commission’s goals to encourage longerterm uses of the transmission system. 

Our revised policy on priority for preconfirmed requests thus addresses the 

comments that we should preserve the 

priority of longer duration requests for 

transmission service over shorter 

duration requests for transmission 

service. For instance, a pre-confirmed 

daily or hourly request will not preempt 

a weekly request that has not been preconfirmed. Pre-confirmed short-term 

service requests therefore will not have 

a priority superior to that of long-term 

service requests that have not been preconfirmed. 

1402. We acknowledge that our 

revised policy on priority for preconfirmed requests may be less effective 

than the NOPR proposal in alleviating 

the problems that arise when 

transmission customers submit multiple 

identical requests for service. However, 

we have taken other steps—notably 

accepting the NAESB business practices 

on queue flooding and queue 


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834See Order No. 676 at P 19. 

835See Order No. 676. 

836E.g., EEI and MidAmerican. 

hoarding 834—that we believe will 

substantially reduce the instances of 

multiple identical requests for service. 

1403. The Commission also 

acknowledges the concerns expressed 

regarding operational difficulties caused 

by giving priority to pre-confirmed 

requests and clarify our policy as 

follows. First, we will prohibit 

transmission customers from 

withdrawing pre-confirmed non-firm 

and short-term firm point-to-point 

transmission service requests prior to 

when the transmission customer is 

offered service or a system impact 

study. This policy will address 

MidAmerican’s concern that a 

transmission customer may withdraw a 

pre-confirmed request for transmission 

service at any time prior to acceptance 

by a transmission provider. We believe 

prohibiting withdrawal of a preconfirmed request is less 

administratively burdensome than the 

non-refundable deposit on requests 

proposed by Nevada Companies and 

achieves the same goals. The 

Commission will allow transmission 

providers to invalidate a pre-confirmed 

request at the request of the 

transmission customer in the very near 

term following submittal of the request, 

in the event the transmission customer 

makes an inadvertent error in 

submitting its request. We expect the 

transmission provider to log such 

occurrences as an act of discretion so we 

can verify that transmission customers 

are not abusing this flexibility. 

1404. Second, while the Commission 

recognizes that a customer submitting a 

pre-confirmed request is not bound to 

take service when the transmission 

provider counteroffers the transmission 

customer’s initial request, we do not 

believe this fact alone warrants 

reversing our proposal to give a priority 

to pre-confirmed requests. We are 

satisfied that a transmission customer 

that pre-confirms its request is obligated 

to take full service in the event the 

transmission provider offers the service 

requested. 

1405. The Commission also believes 

the revised priority policy will address 

Southern’s comment that a preconfirmed service request submitted 

within close proximity to the actual 

commencement of service should not 

preempt an existing non-pre-confirmed 

request if doing so would be disruptive 

to the operations of the transmission 

provider or to the reliability of the 

system itself. A pre-confirmed request 

for transmission service will not preempt an equal duration request that has 

already been confirmed. Therefore, the 

effects of the priority for pre-confirmed 

requests will be resolved prior to the 

time when the transmission provider 

would require an accepted request to be 

confirmed. Handling priority for preconfirmed requests should be no more 

disruptive than giving a transmission 

customer time to confirm an accepted 

request. 

1406. Excluding long-term requests 

for transmission service will mitigate 

many of the concerns expressed by 

commenters who argued that giving a 

priority to pre-confirmed requests will 

unfairly disadvantage transmission 

customers who are requesting service in 

response to a request for proposals and 

are therefore not in a position to preconfirm their requests. Such requests for 

proposals typically involve long-term 

contracts for energy and/or generating 

capacity and, therefore, would be linked 

most likely to long-term transmission 

service requests. We disagree, however, 

with EEI’s characterization of the 

Commission’s decision in Order No. 638 

to give a priority to pre-confirmed 

requests for non-firm service only if the 

request offers a higher price. The 

Commission’s decision in that 

proceeding was driven by its 

interpretation that the proposed 

business practice addressed in the part 

of Order No. 638 cited by Southern was 

not consistent with the relevant section 

of the pro forma tariff. In addition, the 

Commission’s experience since Order 

No. 638 and the comments received to 

the NOPR proposal indicate the value of 

giving a priority to pre-confirmed 

requests, despite concerns that some 

transmission customers are not in a 

position to pre-confirm their requests 

for transmission service. 

1407. In response to requests for 

clarification from MidAmerican and 

TranServ, we clarify that a new preconfirmed request for transmission 

service would preempt a request of 

equal duration that has been accepted 

by the transmission provider but not yet 

confirmed by the transmission 

customer. Thus, we decline to adopt 

TDU Systems’ suggestion that the 

Commission include a time window 

between acceptance of a request and 

confirmation of the request, during 

which a request can not be preempted 

by a pre-confirmed request for 

transmission service. This is consistent 

with our desire to give transmission 

service first to those customers that are 

committed to taking the transmission 

service if it is granted. In the case of 

monthly firm point-to-point 

transmission service, the transmission 

customer has up to four days to confirm 

an accepted request. This is a 

potentially long delay when there is 

another transmission customer that is 

willing to commit to take the same 

service. Moreover, this policy is 

consistent with NAESB business 

standard 001–4.25, which allows a preconfirmed request for non-firm point-topoint transmission service to preempt a 

request of equal duration and lower 

price that has been accepted but not 

confirmed.835

(2) Price as a Tie-Breaker 

NOPR Proposal 

1408. The NOPR also proposed to add 

price as a tie-breaker in determining 

reservation queue priority when the 

transmission provider is willing to 

discount transmission service. Under 

the Commission’s proposal, price would 

serve as a tie-breaker after preconfirmation for those requests that are 

not yet confirmed. 

Comments 

1409. All of the commenters who 

address the Commission’s proposal to 

add price as a tie-breaker support the 

proposal, although some request that it 

be modified or clarified. Several 

commenters ask the Commission to 

clarify that an otherwise higher queued 

request has a right to match the price 

offer of a request with a higher price.836

With regard to short-term service, 

WAPA believes that the Commission’s 

proposal to add price as a tie-breaker 

would overly complicate matters after 

taking into account the many complex 

timing restrictions on short-term 

service. As a result, WAPA proposes 

that the Commission limit application of 

its proposal to requests for long-term 

transmission service. MISO/PJM States 

suggest that the Commission consider 

requiring point-to-point transmission 

customers to offer a reservation price at 

which they would be willing to sell 

their transmission service. 

Commission Determination 

1410. The Commission adopts the 

NOPR proposal to add price as a tiebreaker in determining reservation 

queue priority when the transmission 

provider is willing to discount 

transmission service. As a result, price 

will serve as a tie-breaker after preconfirmation for those requests that 

have not yet been confirmed by the 

transmission customer or have not yet 

been evaluated by the transmission 

provider. Consistent with the principles 

currently embodied in the pro forma 

OATT and articulated in Order No. 638, 

we clarify that, in the event a later 

queued short-term request for 


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837See Order No. 638 at 31,442. 

838E.g., Bonneville and Santa Clara. 

839E.g., TDU Systems and NRECA. 

840E.g., Bonneville and CREPC. 

841E.g., Bonneville and Nevada Companies. 

842E.g., Bonneville and NRECA. 

843E.g., EEI, MidAmerican, Ameren, 

Constellation, Entergy, NorthWestern, PNM-TNMP, 

WAPA, Powerex, and Indianapolis Power Reply. 

844E.g., Powerex and TranServ. 

845 Id. 

transmission service preempts a 

conditional confirmed short-term 

request for transmission service based 

on price, then the conditional confirmed 

request has a right to match the price 

offer of the later queued request.837

1411. We disagree with WAPA’s 

proposal to limit application of the 

NOPR proposal to requests for long-term 

transmission service. We believe the 

addition of price as a tie-breaker for 

discounted firm point-to-point 

transmission service is an economically 

efficient policy for both short-term and 

long-term firm point-to-point 

transmission service. We recognize that 

adding another element to the 

reservation priority criteria adds 

additional complexity. However, we 

believe that the efficiency gains warrant 

any additional complexity in the few 

cases in which transmission customers 

bid for transmission service. 

1412. We do not agree with MISO/ 

PJM States’ suggestion that the 

Commission require point-to-point 

transmission customers to offer a 

reservation price at which they would 

be willing to sell their transmission 

service. The transmission provider may 

already make unscheduled firm 

transmission service available to other 

customers on a non-firm basis and we 

have adopted proposals that we believe 

will encourage transmission customers 

to voluntarily offer to sell firm point-topoint transmission service on the 

secondary market as described in 

section V.C.4 of this Final Rule. As a 

result, we see no reason to require a firm 

point-to-point customer to offer its 

reserved capacity for sale. 

(3) Five-Minute Window for Requests 

NOPR Proposal 

1413. In the NOPR, the Commission 

responded to comments that 

transmission customers that have the 

financial resources to purchase software 

and employ staff to continually monitor 

OASIS sites have an unfair advantage 

under a first-come, first-served approach 

by seeking comment on whether any 

such advantage would be mitigated if all 

requests submitted within a five-minute 

window were deemed to have been 

submitted simultaneously. The 

Commission also sought comment on 

whether transmission customers could 

game a five minute equivalent priority 

standard to request transmission service 

only after another transmission 

customer has made a request. The 

Commission further sought comment on 

how to allocate limited transmission 

capacity among equivalent priority 

requests of equal duration, in the event 

a five minute equivalent priority 

standard is adopted. 

Comments 

1414. Many of the commenters in the 

West support the proposal to treat 

transmission requests submitted within 

some specified period of time as 

submitted simultaneously. Supporters 

of a time window within which all 

requests would be deemed to have been 

submitted simultaneously argue that the 

proposal would give transmission 

customers who are less sophisticated 

and have fewer financial resources 

equal access to transmission service.838

Other supporters argue that such a time 

window would be particularly 

appropriate in circumstances when a 

tariff calls for requests to be submitted 

‘‘no earlier than’’ a specific deadline.839

In its reply comments, NRECA argues 

that a customer attempting to plan a 

request under such circumstances may 

miss being the first in time by a matter 

of seconds because its computer is 

slower than another customer’s 

computer. 

1415. Supporters of the proposal 

suggest a number of modifications to the 

Commission’s suggested five-minute 

window. A number of commenters 

suggest a window longer than five 

minutes.840 For instance, Bonneville 

proposes a system similar to PJM’s 30 

minute window for monthly service. On 

the other hand, Manitoba Hydro 

suggests a shorter window and a limit 

on the number and size of requests, 

claiming this would reduce the 

potential for gaming and/or anticompetitive behavior. A number of 

commenters also suggest that such a 

system should be limited to short-term 

transmission service 841 and/or should 

not apply to requests for transmission 

service submitted close to the hour that 

service commences.842 In its reply 

comments, PNM–TNMP asserts that, if 

the Commission implements a fiveminute window policy, then the policy 

should not be limited to long-term 

transactions. In its reply comments, 

NRECA argues that requests submitted 

within a five-minute window should 

not be publicly available until the 

window has closed in order to prevent 

competitors from requesting the same 

service simply to disrupt the 

transmission service procurement 

process. Similarly, Bonneville suggests 

that the reservation process should be 

conducted like a blind auction, so that 

requests are not visible on OASIS until 

the window closes. 

1416. Many of the large power 

marketers and transmission providers in 

the East oppose the notion of a 

submittal window. Opponents of a time 

window within which all requests 

would be deemed to have been 

submitted simultaneously suggest that 

the proposal is an unnecessary 

complication and may actually be 

counterproductive to the Commission’s 

ultimate goal due to issues regarding 

how transmission service would be 

allocated among simultaneous 

requests.843 EEI notes that there is no 

limit on how far in advance a 

transmission customer may submit 

requests for firm transmission service, 

so the likelihood that any two requests 

are submitted within the same five 

minute period is low. Powerex argues 

that the simplicity of the first-come, first 

served approach limits the number of 

disputes. In its reply comments, 

Powerex argues that none of the 

commenters that favor a five-minute 

window addressed the operational 

problems that such a proposal would 

generate. 

1417. Some commenters argue that a 

pro rata allocation of simultaneous 

requests of equal duration will result in 

all transmission customers acquiring 

less transmission service than they need 

to complete their wholesale 

transactions.844 As a result, these 

commenters suggest that the need to 

provide transmission customers with 

usable quantities of transmission service 

will necessarily lead to developing an 

allocation protocol in addition to 

allocating based on time submitted and 

duration of request.845 Powerex argues 

that any system that creates a time 

window within which all requests 

would be deemed to have been 

submitted simultaneously will lead 

transmission customers to inflate the 

quantity of service they request in order 

to get quantity of service they actually 

desire. Other commenters make 

suggestions regarding the manner by 

which transmission service should be 

allocated among simultaneously 

submitted requests. Bonneville believes 

that each transmission provider should 

develop an allocation method 

appropriate to its system. CREPC 

suggests that price be used as a 

secondary tie-breaker after duration. 

TDU Systems argue that using duration 


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12450 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

846See NAESB Business Practice Standard 001–

4.13. 

847For instance, Idaho Power Company has 

adopted a business practice that requests for 

monthly firm transmission service cannot be 

submitted earlier than 11 months prior to operation. 

Portland General Electric has adopted a business 

practice that Daily Firm ATC on the CaliforniaOregon Intertie will be posted at or about 7:11 a.m. 

Pacific on the day prior to operation and that 

requests that are submitted prior to ATC being 

posted will be refused. SPP has modified its tariff 

so that requests for monthly firm transmission 

service cannot be submitted more than 90 days 

prior to the first day of operation. 

as a tie-breaker for simultaneous 

requests could discriminate against 

purchased power contracts that are 

designated as network resources. 

Commission Determination 

1418. Based on the comments 

received, it appears that the desire for a 

time window within which all requests 

would be deemed to have been 

submitted simultaneously is largely 

limited to market participants in the 

Western Interconnection. With one 

exception, we will not mandate a 

change to our current first-come, firstserved policy to address an issue that 

appears to be regional in nature. Rather, 

we will allow transmission providers to 

propose a window within which all 

transmission service requests the 

transmission provider receives will be 

deemed to have been submitted 

simultaneously. Transmission providers 

will have discretion to determine which 

transmission services will be subject to 

a submittal window policy. We believe 

the transmission provider is in the best 

position to determine whether it can 

accommodate a submittal window for a 

specific transmission service and the 

need for such a window. 

1419. In order to ensure that 

transmission service is not awarded in 

an arbitrary fashion and to ensure that 

transmission customers who are less 

sophisticated and have fewer financial 

resources have equal access to 

transmission service, we will require 

transmission provider who set a ‘‘no 

earlier than’’ time for request submittal 

to treat all transmission service requests 

received within a specified period of 

time as having been received 

simultaneously. We agree with those 

commenters that argue that a time 

window within which all requests 

would be deemed to have been 

submitted simultaneously is particularly 

appropriate in circumstances when a 

tariff or business practice calls for 

requests to be submitted no earlier than 

a specific deadline. As NRECA argues, 

there is no meaningful difference 

between requests for transmission 

service that are identical in all respects 

except that one request is received by 

the transmission provider seconds 

ahead of another request because one 

customer’s computer is slower than 

another customer’s computer. EEI is 

correct that NAESB’s uniform business 

practices do not limit how far in 

advance a transmission customer may 

submit requests for firm transmission 

service.846 However, a number of 

transmission providers have modified 

their tariffs or adopted business 

practices that mandate that requests can 

be submitted no earlier than a specific 

deadline.847 In these instances, multiple 

requests for transmission service can be 

submitted at approximately the same 

time. We generally agree with Powerex’s 

assertion that the simplicity of the 

current first-come, first served approach 

limits the number of disputes. However, 

when a transmission provider 

establishes a ‘‘no earlier than’’ deadline, 

submittals that are received by the 

transmission provider within a matter of 

seconds cannot be meaningfully 

differentiated. A transmission provider 

with such a business practice or tariff 

provision will be required to modify its 

tariff to include its proposed specified 

period of time. We will evaluate each 

proposal on a case-by-case basis, as 

described below. 

1420. We will allow transmission 

providers to propose the period of time 

within which all requests would be 

deemed to have been submitted 

simultaneously. We believe the 

transmission provider is in the best 

position to identify the window it can 

operationally accommodate. We expect 

the submittal window to be open for at 

least five minutes unless the 

transmission provider can present a 

compelling rationale to justify a shorter 

submittal window. 

1421. We agree with NRECA and 

Bonneville’s suggestion that requests 

submitted within a specified window 

should not be publicly available until 

the window has closed in order to 

prevent competitors from requesting the 

same service simply to disrupt the 

transmission service procurement 

process. 

1422. We will require each 

transmission provider that is required 

to, or decides to, deem all requests 

submitted within a specified period as 

having been submitted simultaneously 

to propose a method for allocating 

transmission capacity if sufficient 

capacity is not available to meet all 

requests submitted within the specified 

time period. We agree with Bonneville 

that the transmission provider is in the 

best position to determine an allocation 

that is appropriate to its system and that 

cannot be gamed in the manner 

suggested by Powerex and TranServ. We 

believe that transmission providers will 

be able to develop allocation methods, 

like the method PJM uses to allocate 

monthly firm point-to-point 

transmission service, that address the 

operational issues Powerex and 

TranServ raise. 

(4) Right of First Refusal and 

Preemption 

1423. While not specifically 

addressed in the NOPR, a few 

commenters use the Commission’s 

proposed introduction of hourly firm 

service, discussed above, to argue that 

the Commission should take the 

opportunity to clarify or revise the right 

of first refusal for short-term 

transmission service requests. 

1424. To understand commenter 

concerns, it is useful to note the relevant 

components of the reservation and 

scheduling process in the pro forma 

OATT. Reservations for short-term firm 

point-to-point transmission service are 

available on a first-come, first-served 

basis and are conditional based upon 

the length of the requested transaction 

as explained further below. If the 

transmission system becomes 

oversubscribed, longer-term service may 

preempt shorter-term service, up to a 

specified period. The shorter-term 

reservation holder has a right of first 

refusal to match the longer-term 

reservation, but such right must be 

exercised within 24 hours of being 

notified of the competing reservation, or 

earlier to comply with the scheduling 

deadline. 

Comments 

1425. Salt River argues that the time 

required to administer the right of first 

refusal—which includes contacting 

customers and allowing time to exercise 

the right of first refusal—is 

overwhelming. Salt River argues that the 

current OASIS business practices do not 

permit adequate time to implement 

these rules, and the industry lacks the 

software to either streamline the effort 

or ensure quality control. Salt River 

contends that for hourly, daily, and 

weekly requests, the complexity and 

potentially unjust results of 

administering preemption and the right 

of first refusal rules outweighs any 

potential benefits. Accordingly, Salt 

River recommends revisions to the pro 

forma OATT that make the right of first 

refusal available only to monthly 

requests for service. 

1426. To address the complications 

arising from preemption and the right of 

first refusal, Duke proposes several 

revisions to the pro forma OATT: only 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12451 

848 Morgan Stanley Capital Group v. Illinois 

Power Co., 83 FERC ¶ 61,204 at 61,911–12 (1998), 

order on reh’g, 93 FERC ¶ 61,081 (2000) (MSCG). 

849Wisconsin Public Power Inc. v. Wisconsin 

Public Service Corp., 84 FERC ¶ 61,120 at 61,650–

51 (1998) (WPPI). 

850 Id. 

pre-confirmed requests would trigger 

preemption; confirmed requests could 

not be displaced by longer-term 

requests; only monthly customers 

subject to preemption would be given a 

right of first refusal (Salt River proposes 

a similar OATT revision); and, profiled 

requests (i.e., requests for transmission 

that may have different MW values for 

each hour of the day, and may even 

include some hours where the MW 

value is zero) would not be granted 

priority over confirmed reservations. 

TranServ also asks the Commission to 

provide guidance establishing the 

earliest and latest submission times and 

maximum successive or consecutive 

terms of service required. TranServ 

contends it is unreasonable that a 

request for daily firm service could be 

submitted years in advance and then 

have a right of first refusal to match any 

longer-term request for service. 

1427. To eliminate the potential for 

more complexity, TranServ requests that 

the Commission eliminate the 

conditional nature of short-term pointto-point service under the OATT. 

Whether the Commission adopts this 

recommendation, TranServ further 

recommends that the Commission revise 

the timing provisions for requesting 

short-term point-to-point service to 

reduce overlap for submission of 

requests that would trigger the need for 

preemption. TranServ and Duke 

recommend a reservation or bidding 

process in which one increment of 

service (monthly, weekly, daily, and 

hourly) is available at a time, with each 

successive shorter increment of service 

becoming available after the reservation 

or bidding window for the preceding 

longer increment has closed. 

1428. NorthWestern requests that the 

Commission clarify whether the terms 

‘‘reservation’’ and ‘‘request’’ used in 

section 13.2 (Reservation Priority) are 

used interchangeably. If they are not 

used interchangeably, and ‘‘reservation’’

is meant to be a confirmed request, 

while ‘‘request’’ is a queued request that 

has not been confirmed, NorthWestern 

suggests that the sentence that includes 

the two uses of ‘‘reservation’’ creates 

confusion because, if both requests are 

confirmed, then either sufficient 

capacity exists to accept both requests, 

or the transmission provider accepted 

requests that exceed the ATC. To avoid 

confusion, then NorthWestern 

recommends that the second use of 

‘‘reservation’’ should be changed to 

‘‘request.’’ If so, to avoid the suggestion 

that the section is attempting to 

distinguish between requests that have 

been confirmed from those simply 

queued, NorthWestern recommends that 

the Commission consider changing all 

of the ‘‘reservation’’ references to 

‘‘request.’’

Commission Determination 

1429. Based on the issues raised in 

comments, we find that changing the 

‘‘first come, first served’’ nature of the 

reservation process and right of first 

refusal process is not warranted at this 

time. The ‘‘first-come, first-served’’

principle facilitates the administration 

of the reservation process and benefits 

customers because there can be little 

confusion about how to comply with it. 

1430. The remaining concerns 

regarding administering the right of first 

refusal are addressed below. First, when 

a longer-term request seeks capacity 

allocated to multiple shorter-term 

requests, the shorter-term customers 

should have simultaneous opportunities 

to exercise the right of first refusal. 

Duration, pre-confirmation status, price, 

and time of response would then be 

used to determine which of the shorterterm requests will be able to exercise the 

right of first refusal, consistent with the 

Commission’s tie breaking provision in 

section 13.2(ii). Second, to minimize the 

potential for gaming, a preempting 

longer request must be for a fixed 

capacity over the term of the request. 

1431. We agree with NorthWestern’s 

assertion that the sentence in section 

13.2(iii) of the pro forma OATT that 

includes the two uses of ‘‘reservation’’

creates confusion. Therefore, we clarify 

that the terms ‘‘reservation’’ and 

‘‘request’’ are not used interchangeably; 

‘‘reservation’’ is meant to be a confirmed 

request, while ‘‘request’’ is a queued 

request that has not been confirmed. To 

clarify the distinction between use of 

the terms ‘‘request’’ and ‘‘reservation’’

in section 13.2(iii), we will revise that 

section so that the sentence ‘‘Before the 

conditional reservation deadline, if 

available transfer capability is 

insufficient to satisfy all Applications, 

an Eligible Customer with a reservation 

for shorter-term service has the right of 

first refusal to match any longer-term 

reservation before losing its reservation 

priority’’ is replaced by the sentence 

‘‘Before the conditional reservation 

deadline, if available transfer capability 

is insufficient to satisfy all Applications, 

an Eligible Customer with a reservation 

for shorter-term service has the right of 

first refusal to match any longer-term 

request before losing its reservation 

priority.’’

6. Designation of Network Resources 

a. Qualification as a Network Resource 

1432. Taken together, the following 

sections of the pro forma OATT 

describe the resources a network 

customer can appropriately designate as 

a network resource. Section 30.1 of the 

pro forma OATT describes network 

resources as all generation owned or 

purchased by the network customer 

designated to serve network load under 

the tariff. Section 30.1 also indicates 

that network resources may not include 

resources that are committed for sale to 

non-designated third-party load or 

otherwise cannot be called upon to meet 

the network customer’s network load on 

a noninterruptible basis. Pursuant to 

section 30.7 of the pro forma OATT, the 

network customer must demonstrate 

that it owns or has committed to 

purchase generation pursuant to an 

executed contract in order to designate 

a generating resource as a network 

resource. Alternatively, the network 

customer may establish that execution 

of a contract is contingent upon the 

availability of network service. Section 

29.2 requires the network customer to 

provide the following information about 

a power purchase agreement that is to 

serve as a new designated network 

resource: source of supply, control area 

location, transmission arrangements and 

delivery point(s) to the transmission 

provider’s transmission system. 

1433. As the Commission noted in the 

NOPR, a number of orders address what 

types of resources meet the criteria set 

out in sections 30.1 and 30.7 of the pro 

forma OATT. In MSCG, the Commission 

stated that network resources must be 

generating resources owned by the 

network customer or purchases of 

noninterruptible power under executed 

contracts that require the network 

customer to pay for the purchase.848 In 

WPPI, the Commission found that a 

network customer can designate as a 

network resource a system purchase that 

is not backed by a specific generator.849

The Commission found that Wisconsin 

Public Service Corporation (WPS) had 

appropriately designated a power 

purchase as a network resource, even 

though the power purchase agreement 

did not require WPS to take energy 

around the clock and allowed WPS to 

convert its energy purchase to a 

discounted product that could be 

interrupted.850 In addition, the 

Commission stated that, because the pro 

forma OATT requires a power purchase 

to be noninterruptible, third-party 

transmission arrangements to deliver 

the resource to the network have to be 


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851 Id. at 61,660. 

852 Illinois Power Co., 102 FERC ¶ 61,257 at P 14 

(2003), reh’g denied, 108 FERC ¶ 61,175 (2004) 

(Illinois Power). 

853E.g., Ameren, BART, Constellation, Duke, 

Entegra, Entergy, Morgan Stanley, MISO, 

NorthWestern, Progress Energy, Sempra Global, 

Southern, Suez Energy NA, and TranServ. 

854E.g., AMP-Ohio, APPA, Duke, EEI, Entergy, 

Fayetteville, Morgan Stanley, NCPA, Northwest 

IOUs, Northwest Parties, MISO/PJM States, PGP, 

Pinnacle, PNM–TNMP, Salt River, Sempra Global, 

Southern, TAPS, Utah Municipals, and WSPP. 

855E.g., AMP-Ohio, Northwest IOUs, NRECA 

Reply, PGP, Pinnacle, Sempra Global, Strategic 

Energy Reply, and TAPS. 

856 Dynegy Midwest Generation, 101 FERC 

¶ 61,295 (2002), reh’g dismissed, 108 FERC ¶ 61,175 

(2004) (Dynegy). 

857E.g., Duke, Dynegy Reply, EEI, and Southern. 

858 Dynegy at P 21. 

859E.g., Duke, EEI and Southern. EEI notes that 

its Firm LD Product is distinct from its ‘‘System 

Firm’’ and ‘‘Unit Firm’’ products in its Master 

Power Purchase and Sale Agreement, each of which 

excuses a failure to perform only for force majeure 

and neither of which permits a party to fail to 

perform and pay liquidated damages. 

860E.g., Hoosier Reply, Strategic Energy Reply, 

and Utah Municipals. 

noninterruptible as well.851 In Illinois 

Power, the Commission found that a 

firm purchase need not be backed by a 

capacity purchase to qualify as a 

network resource.852

NOPR Proposal 

1434. In the NOPR, the Commission 

proposed to maintain its current policy 

regarding the power purchase 

agreements that network customers may 

designate as network resources. In 

particular, the Commission proposed 

that a network customer would continue 

to be able to designate resources from 

system purchases not linked to a 

specific generating unit, provided the 

power purchase agreement is not 

interruptible for economic reasons, does 

not allow the seller to fail to perform 

under the contract for economic 

reasons, and requires the network 

customer to pay for the purchase. In 

addition, the Commission reiterated that 

third-party transmission arrangements 

to deliver the purchase to the network 

must be noninterruptible. 

1435. Regarding seller’s choice 

contracts, the Commission explained 

that a power purchase agreement that is 

structured so that a network customer 

cannot specify all of the information 

required by section 29.2(v) of the pro 

forma OATT cannot be designated as a 

network resource. Specifically, the 

Commission reiterated that a request to 

designate a new network resource must 

provide the information including the 

source of supply, control area location, 

transmission arrangements, and delivery 

point(s) to the transmission provider’s 

transmission system. The Commission 

proposed that, when designating a 

system purchase as a new network 

resource, a network customer must 

identify the resource as a system 

purchase as well as the control area 

from which the power will originate. 

1436. In response to suggestions that 

liquidated damages (LD) products 

should not be designated network 

resources because they are interruptible 

for economic reasons, the Commission 

proposed to clarify that network 

customers may not designate as network 

resources those power purchase 

agreements that give the seller a 

contractual right to compensate the 

buyer instead of delivering power even 

if the seller is able to deliver power. For 

instance, the Commission proposed that 

a network customer may not designate 

as a network resource a purchase 

agreement that allows the seller to 

interrupt sales under the purchase 

agreement for reasons other than 

reliability, but allows the buyer to force 

delivery at a higher price. In addition, 

the Commission proposed that a 

network customer may not designate as 

a network resource a purchase 

agreement that requires a seller to pay 

the buyer’s cost of replacement power 

when the seller chooses not to deliver 

energy for economic reasons. 

Comments Overview 

1437. Most commenters argue that the 

Commission must provide further 

clarification than given in the NOPR, 

particularly with regard to the eligibility 

of firm LD power products and the 

information required by section 29.2(v) 

of the pro forma OATT for seller’s 

choice contracts. Various commenters 

also argue that the Commission’s 

precedent on this issue is contradictory 

and that the Commission’s policy with 

respect to designation of network 

resources may violate section 217 of the 

FPA and conflict with state jurisdiction. 

(1) LD Contracts 

Comments 

1438. Many commenters express 

general support for some or all of the 

Commission’s clarifications in the 

NOPR with regard to ineligibility of 

resources which are interruptible for 

economic reasons and/or that allow the 

seller to compensate the buyer instead 

of delivering power even if the seller is 

able to deliver power.853 However, 

many commenters express concern 

about the clarity of the policy.854

1439. In particular, several parties 

contend that it is in fact the firmness of 

the contract and not the mere existence 

of an LD provision describing the 

remedies in case of a failure to perform 

that determines the eligibility of a 

power purchase agreement to be 

designated as a network resource.855

TAPS argues that, in order to determine 

the firmness of a purchase, one must 

look at the criteria for excusing a failure 

to supply. AMP-Ohio, MISO, and NCPA 

also express support for this position, 

pointing to the Commission’s finding in 

Dynegy 856 that the inclusion of an LD 

provision in EEI’s Master Power 

Purchase and Sale Agreement’s Firm LD 

product (EEI’s Firm LD Product) does 

not inherently make that product less 

firm. 

1440. Several commenters argue that, 

when the Commission in Dynegy 

considered the acceptability of EEI’s 

Firm LD Product as a designated 

network resource, it neglected to 

consider the presence of a provision 

which appears to contradict its 

decision.857 They point to the 

Commission’s statement in Dynegy that 

EEI’s Firm LD Product ‘‘does not permit 

the power to be interrupted for 

economic reasons, or at the discretion of 

either party, but only if a force majeure 

occurs.’’ 858 Some contend that the 

Commission’s conclusion ignored the 

fact that EEI’s Firm LD Product actually 

allows power to be interrupted for any 

reason, including economic reasons, 

after which the agreement then provides 

LDs as a remedy if the interruption was 

not due to a force majeure event.859

Duke and EEI note that contracts under 

EEI’s Firm LD Product agreement or 

similar agreements have become 

commonplace since the Commission’s 

Dynegy decision and that clarification 

regarding their use as network resources 

is required to address industry 

confusion. 

1441. Several commenters disagree 

that the EEI Firm LD Product gives 

parties the right to interrupt for any 

reason, including economic reasons, 

provided that LDs are paid by the nonperforming party.860 Hoosier argues on 

reply that EEI and Southern have 

misunderstood the Commission’s intent 

in Dynegy. Hoosier contends that the 

Commission correctly found in Dynegy 

that the EEI Firm LD Product does not 

permit power to be interrupted for 

economic reasons, or at the discretion of 

either party, but only if a force majeure 

event occurs. Thus, Hoosier argues, the 

EEI Firm LD Product does not give the 

seller a right to interrupt for any reason 

other than force majeure, and any seller 

that interrupts for economic reasons is 

clearly in breach of its obligations to 

perform under the contract and must 


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861E.g., APPA, Hoosier Reply, NCPA, Southern, 

Strategic Energy Reply, and Utah Municipals. 

862E.g., EEI, Hoosier Reply, Southern and NCPA. 

863MISO/PJM States similarly argue that whether 

a particular contract with LD provisions can serve 

as a designated resource should be decided within 

the RTO stakeholder process. 864E.g., APPA Reply, Morgan Stanley, and NCPA. 865E.g., Duke, Dynegy, and Detroit Edison Reply. 

866E.g., APPA, EEI, Entergy, Northwest Parties, 

Salt River, Utah Municipals, and WSPP. 

pay damages. Hoosier acknowledges 

that a seller always has the choice of not 

performing its obligations and paying 

damages, but that is not peculiar to the 

EEI Firm LD Product. Hoosier maintains 

that any party to any contract has the 

ability, but not the right, to breach its 

obligations under the contract and pay 

damages. According to Hoosier, the only 

difference in the case of the EEI Firm LD 

Product is that the parties have 

stipulated beforehand as to the measure 

of the damages required of a seller in 

breach, in order to minimize litigation 

over damages. This stipulation, Hoosier 

argues, conveys no additional 

substantive rights on either party. 

1442. Several parties note that firm 

LD contracts account for a significant 

number of currently utilized products 

and that disallowing these product to be 

designated as network resources may 

create significant disruption.861

Commenters supporting continued use 

of firm LD contracts as designated 

network resources argue that allowing 

products structured on EEI’s Firm LD 

Product has not created reliability 

problems.862 Southern argues that the 

Commission should not set criteria that 

would place in jeopardy an array of 

products that have a firm LD dimension. 

Southern further states that such 

products are among the most reliable in 

instances where market prices are very 

high (where LDs could be quite 

substantial) and that just about any 

power purchase/sale contract can be 

financially settled in real-time or for a 

given period in lieu of physical delivery 

during that period. The fact that some 

contracts set out in advance the terms of 

such settlement (so to render commerce 

more efficient and liquid) does not, 

Southern argues, render those contracts 

any less qualified for designation as 

network resources. Thus, Southern 

encourages the Commission to 

reconsider its revised guidance 

regarding the ineligibility of contracts 

structured after EEI’s Firm LD Product. 

Utah Municipals agrees, and similarly 

requests that contracts under EEI’s Firm 

LD Product be allowed to qualify as 

network resources. 

1443. Morgan Stanley argues that the 

notion that firm LD contracts do not 

contribute as much to resource 

adequacy as contracts tied to individual 

physical resources is inaccurate. Morgan 

Stanley contends that the incentive to 

ensure performance is far greater with a 

firm LD obligation than with unit 

contingent and system firm contracts. 

Morgan Stanley explains that unit 

contingent and system firm contracts 

require delivery if the unit or group of 

units performs and excuses delivery if 

they do not, while a Firm LD obligation 

requires delivery so long as it is 

physically possible to achieve delivery, 

regardless of the cost of doing so. Thus, 

according to Morgan Stanley, firm LD 

products can enhance supply security 

because they are not dependent upon 

the performance of an individual unit or 

units, but rather put the burden and 

opportunity on the supplier to use 

multiple physical resources to meet its 

obligations. 

1444. APPA also requests 

reconsideration of this issue, arguing 

that its members are often presented 

with power purchase agreements based 

on EEI’s Firm LD Product and that they 

are not always successful in negotiating 

amendments to such agreements with 

suppliers. APPA argues that an LSE can 

use a diverse resource portfolio, 

including firm LD power purchase 

agreements, to serve its load 

economically, while meeting reliability 

requirements and advancing other 

important policy objectives (diverse fuel 

mix, use of renewable energy, etc.). 

APPA urges the Commission to allow 

such use if it is consistent with the 

commercial practices in a region.863

1445. NCPA also opposes forbidding 

firm LD products without looking more 

fully into their merits and the potential 

safeguards that could be built into them. 

NCPA recognizes that firm LD contracts 

raise certain issues under the pro forma 

OATT and also pose issues for planning 

where a specific resource is not 

designated, but these problems are not 

significantly different from the problems 

of a large transmission owner 

designating its entire fleet as network 

resources for its entire load. Rather than 

ban LD contracts from an important 

segment of the market, several 

commenters suggest that the 

Commission convene a separate 

proceeding or conference to further 

investigate the issue.864

1446. Other commenters argue against 

allowing the designation as network 

resources of contracts that permit the 

interruption of power sales for reasons 

other than reliability as long as LDs are 

paid.865 Detroit Edison argues in its 

reply comments that a seller’s decision 

to pay the ‘‘costs of ‘cover’ ’’ under these 

contracts is of no value to an LSE that 

lacks deliverable alternatives. Detroit 

Edison further claims that, contrary to 

Southern’s assumption that a failure to 

deliver under a firm LD contract would 

result in substantial non-delivery 

penalties, one would expect a supplier 

afforded the option to divert power to a 

higher priced market that produces a net 

financial gain would elect to interrupt 

service under the power sales contract 

and pay the LDs. Detroit Edison 

contends that purchasers would be left 

hanging during periods of supply 

shortage when firm physical supply is 

most critical. 

1447. In its reply comments, Duke 

asserts that allowing firm LD products 

to be designated as network resources 

would result in network customers 

leaning on its system. Although it has 

doubts about whether the EEI Firm LD 

Product actually contains language that 

prohibits interruptions for economic 

reasons, Duke would find the inclusion 

of such language in purchased power 

agreements to provide sufficient 

firmness to allow the contract to be 

designated as a network resource. In its 

reply comments, Dynegy argues that 

allowing designation of firm LD 

products is simply inconsistent with the 

existing OATT requirements that a 

transmission customer either own, 

purchase or have rights to generation. 

1448. Northwest IOUs request that the 

Commission clarify whether the 

limitations for qualification of a network 

resource, such as the presence or 

absence of an LD clause, would prevent 

a transmission provider from using such 

a resource for service to its bundled 

native load customers. Northwest IOUs 

state that, if the non-rate terms and 

conditions do not apply directly by 

requirement of the Final Rule, but only 

under a comparability test where there 

is a comparison to network customers, 

then that position should be made clear. 

They further note that some 

transmission providers have no 

comparable network service, or no 

service involving generating units 

within the transmission provider’s 

control area. Accordingly, Northwest 

IOUs request that the Commission 

clarify whether, in those instances, the 

limitations for qualification of a network 

resource would apply. 

1449. Many commenters also argue 

for the eligibility of service provided 

under the WSPP Service Schedule C 

(Schedule C) agreement.866 In 

particular, WSPP argues that its 

Schedule C product satisfies the 

Commission’s requirements for 

designation as a network resource 

because it requires the seller to deliver 

power except under very limited 


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867WPPI, 84 FERC at 61,652. 

circumstances, such as force majeure, 

and that the agreement itself clearly 

provides that it is a firm product. 

However, WSPP notes that its product, 

like most if not all wholesale power 

sales contracts, contains a damages 

provision which could be characterized 

as an LD provision. WSPP contends that 

such provision is used simply to avoid 

the need to litigate damages and not to 

permit a seller to ignore its delivery 

obligations by financially settling a firm 

power sale. WSPP states that it is not 

intended that sellers be allowed to 

refuse to deliver for economic reasons. 

Therefore, WSPP requests clarification 

that its Schedule C product is eligible 

for designation as a network resource, 

and notes the potential for significant 

disruptions in the market and WSPP 

member sales of firm products if its 

Schedule C product is not considered 

eligible for designation as a network 

resource. 

1450. EEI and Northwest Parties note 

that, in some instances, both the sellers 

and buyers of the Schedule C product 

designate that product as a network 

resource, since it appears to meet the 

pro forma OATT definition of a network 

resource for both parties because the 

agreement allows interruptions to serve 

native loads. If only one party is found 

to be able to designate the Schedule C 

product as a network resource, EEI 

argues that the other party would run 

the risk of civil penalties for making an 

incorrect attestation and may also lose 

the transmission rights that it needs to 

serve its native load or network load. 

Northwest Parties request specific 

clarification as to whether power 

purchased under Schedule C from a 

seller with public utility or statutory 

obligations to its customers is to be 

considered power available to meet the 

purchaser’s network load on a noninterruptible basis, given that the seller 

may interrupt service under the power 

sales contract to meet its public utility 

or statutory obligations. If the 

Commission decides that the Schedule 

C transactions cannot be designated as 

network resources, Northwest Parties 

asks the Commission to state whether 

such transactions would be eligible if 

the WSPP service agreement requires 

the seller to give the purchaser advance 

notice of an interruption. Salt River also 

asks that, if Schedule C is found to be 

ineligible, the Commission identify the 

specific changes needed to that contract 

to allow for designation. 

1451. Beyond the eligibility of 

contracts with LDs to be designated as 

network resources, EEI and Duke also 

argue that there is a conflict between the 

policy guidance given in Dynegy (that a 

power purchase agreement which is 

interruptible for reasons other than 

reliability is not eligible for designation 

as a network resource) and the guidance 

given in WPPI 867 (that a power 

purchase agreement which permits 

curtailment to serve the seller’s native 

load is eligible for designation as a 

network resource). Duke argues that, 

since the type of contracts contemplated 

in WPPI are clearly interruptible for 

reasons other than reliability, WPPI 

should no longer be deemed valid case 

law in light of the Commission’s 

proposed clarifications in the NOPR. 

Duke argues that allowing such 

contracts to be designated as network 

resources creates reliability risks and 

likely permits two entities to designate 

the same generation as network 

resources. While Duke acknowledges 

that exceptions to this rule may be 

necessary in the Western 

Interconnection, it does not support an 

exception for the Eastern 

Interconnection. EEI argues that the 

conflict between the Dynegy and WPPI 

standards has resulted in different 

transmission providers and customers 

using different standards for designation 

of network resources. EEI therefore asks 

the Commission to clarify precisely 

what contracts qualify as a network 

resource before it implements its 

proposed attestation requirement. 

Commission Determination 

1452. Many commenters seek 

clarification of the eligibility of power 

purchase agreements with LD provision 

to be designated as network resources. 

In clarifying our policy concerning firm 

LD products, we turn first to the 

apparent confusion surrounding the 

Commission’s findings in Dynegy. Duke, 

Dynegy, EEI, and Southern argue that 

the Commission incorrectly found in 

Dynegy that the EEI Firm LD Product 

could not be interrupted for economic 

reasons. These parties argue that the EEI 

Firm LD product actually allows power 

to be interrupted for any reason, 

including economic reasons, after which 

LDs are assessed if the interruption was 

not due to a force majeure event. We 

disagree. As Hoosier points out, the EEI 

Firm LD Product does not permit power 

to be interrupted for economic reasons. 

While any party to any contract can 

choose to fail to perform, that does not 

convey a contractual right to fail to 

perform. The EEI contract clearly 

obligates the supplier to provide power, 

except in cases of force majeure. Thus, 

the contract does not allow interruption 

for economic reasons. The presence of 

an LD provision in the EEI Firm LD 

Product does not permit the seller to 

violate the terms of the contract, but 

rather merely specifies the damages that 

must be paid if the seller fails to 

perform under the contract. As noted by 

many commenters, it is the firmness of 

a power purchase contract, and not 

simply the presence or absence of an LD 

provision, that determines the eligibility 

of that power purchase to be designated 

as a network resource. 

1453. We conclude, however, that the 

firmness of an obligation to provide 

under a contract with an LD provision 

is informed by the particular terms of 

the LD provision. The type of LD 

provision commonly seen in firm LD 

products, such as the EEI Firm LD 

Product, obligates the supplier, in the 

case of interruption for reasons other 

than force majeure, to make the 

aggrieved buyer financially whole by 

reimbursing them for the additional 

costs, if any, of replacement power. In 

contrast to this ‘‘make whole’’ type of 

LD provision, other types of LD 

provisions establish penalties at a fixeddollar amount, cap penalties at some 

level, or are otherwise not equivalent to 

a general ‘‘make whole’’ type provision. 

Under these other types of LD 

provisions, suppliers only need to 

compare their savings from interrupting 

with the specified LD penalty when 

deciding whether to interrupt power 

sales. Because such a consideration may 

not take into account the cost of 

replacement power, such LD provisions 

could lead to inefficient supplier 

interruption and economic harm to the 

buyer. 

1454. We find that a ‘‘make whole’’

LD provision, such as that found in the 

EEI Firm LD Product and in the WSPP 

Schedule C agreement, does not create 

incentives that are incompatible with 

the firmness of the overall product. 

‘‘Make whole’’ LDs require the seller to 

consider the price of the replacement 

power, if it is available, to its original 

buyer if the seller fails to perform under 

the contract. There could, of course, be 

situations where the supplier is still 

presented with a net financial gain and 

has an incentive to interrupt, but those 

incentives would seem to be the same 

incentives faced by a designated 

network resource that is a specific 

generating plant owned by the network 

customer. In such an instance, the 

network customer may determine, from 

time to time, that it is more economic 

to substitute power from an alternate 

source in order to allow the originally 

designated resource to either shut down 

or to sell its output into the wholesale 

market. We find no reason to create 

financial incentives that make 

purchased power designated as a 


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868As discussed below, in section V.D.6.c, 

termination of network resource status may either 

be temporary or indefinite. A firm LD contract that 

does not have a ‘‘make whole’’ LD provision and 

which is grandfathered here may continue to be 

temporarily terminated in order to make third-party 

sales without jeopardizing its eligibility to be 

redesignated after a third-party sale. However, once 

a network resource is indefinitely terminated, it 

must comport with the requirements for LD 

provisions, and all other requirements for 

designation of network resources, before it can be 

redesignated. 

869As discussed below, however, we otherwise 

find that the WSPP Schedule C agreement does not 

comply with the requirements for designation as a 

network resource because it allows for interruption 

for reasons other than reliability. We therefore do 

not need to address requests to clarify that both the 

buying and selling party to a WSPP Schedule C 

contract can designate network resources associated 

with the contract. 

870Northwest Parties request similar clarification 

for designation of purchase contracts from one or 

more specified, individual resources. 

network resource financially ‘‘more 

firm’’ than owned generation. 

1455. Accordingly, we find that the 

inclusion of a ‘‘make whole’’ LD 

provision in a power purchase 

agreement does not disqualify that 

agreement from being designated as a 

network resource. However, other types 

of LD provisions may create incentives 

that are incompatible with the firmness 

of a power purchase agreement. Thus, as 

of the effective date of this Final Rule, 

power purchase agreements designated 

as network resources may only contain 

LD provisions that are of the ‘‘make 

whole’’ type. Conversely, power 

purchase agreements containing LD 

provisions that provide penalties of a 

fixed amount, that are capped at a fixed 

amount, or that otherwise do not require 

the seller to pay an aggrieved buyer the 

full cost of replacing interrupted power, 

are not acceptable. Any contract which 

contains an unacceptable LD provision, 

but otherwise qualifies for designation 

as a network resource and has been 

properly designated as a network 

resource prior to the effective date of 

this Final Rule, will be grandfathered 

only until the earlier of (1) the 

expiration of the current term of the 

power purchase agreement or (2) an 

indefinite termination 868 of the power 

purchase agreement as a designated 

network resource pursuant to section 

30.3 of the pro forma OATT. In response 

to the many comments received, we 

confirm that the LD provisions in both 

the EEI Firm LD Product and the WSPP 

Schedule C agreement are acceptable.869

1456. Detroit Edison argues that a 

seller’s obligation to pay the cost of 

replacement power under firm LD 

contracts is of no value to an LSE that 

lacks deliverable alternatives. Detroit 

Edison appears to assume that, as long 

as an LSE purchasing power had no 

deliverable alternatives from which to 

procure power, a designated supplier 

would not be liable for damages if it 

chose to interrupt power sales to the 

buyer for reasons other than force 

majeure. We disagree. Detroit Edison is 

addressing the fairly unusual 

circumstance where a power supply is 

interrupted, there are no available 

alternatives in the market, and firm load 

therefore must be interrupted. We fail to 

see why this circumstance, and the 

difficulty of calculating damages for lost 

load when it occurs, provides a reason 

why a particular network resource (an 

LD contract) should not qualify under 

the pro forma OATT as a network 

resource. 

1457. We also disagree with Dynegy’s 

argument that allowing the designation 

of firm LD products is inconsistent with 

the existing OATT requirement that a 

transmission customer own, purchase or 

have rights to generation. As discussed, 

firm LD contracts that meet the 

Commission’s requirements for 

designation do create for the buyer a 

contractual right to generation and do 

not contain damage provisions which 

make the actual incentives under such 

contracts incompatible with those 

present in owned generation. 

1458. In response to Northwest IOUs’

request, we also clarify that the presence 

or absence of an LD provision does not 

prevent a transmission provider from 

using such a resource to serve its 

bundled native load customers. Rather, 

as we explain above, it is the type of LD 

provision that is controlling. A power 

purchase contract with a ‘‘make whole’’

remedy could be used to serve native 

load customers. 

1459. We disagree with Duke and 

EEI’s argument that there is a conflict 

between the policy guidance given in 

Dynegy (that a power purchase 

agreement which is interruptible for 

reasons other than reliability is not 

eligible for designation as a network 

resource) and the guidance given in 

WPPI (that a power purchase agreement 

which permits curtailment to serve the 

seller’s native load is eligible for 

designation as a network resource). We 

reiterate the Commission’s finding in 

WPPI that a power purchase agreement 

properly designated as a network 

resource may permit curtailment to 

serve the seller’s native load. Consistent 

with the long-standing definition in 

Order No. 888, ‘‘curtailment’’

contemplates a reduction in service as a 

result of system reliability conditions, 

not economic reasons. 

1460. Although we find that the LD 

provision contained in the WSPP 

Schedule C agreement does not impair 

the firmness of that agreement, we note 

that the agreement otherwise allows 

interruptions in generation service ‘‘to 

meet [the] Seller’s public utility or 

statutory obligations to its customers.’’

Thus, the WSPP Schedule C agreement 

appears to allow interruptions for 

reasons other than reliability and, as a 

result, would not be eligible for 

designation as a network resource under 

the Dynegy or WPPI precedent. We find 

that the provision in the WSPP 

Schedule C agreement allowing for 

interruption of generation service in 

order to serve native load would need 

to be revised to explicitly prohibit 

interruptions for reasons other than 

reliability of service to native load in 

order for that provision to meet the 

requirements established under Dynegy 

and WPPI. 

1461. Maintaining the standard for 

eligibility established in Dynegy and 

WPPI will further the Commission’s 

goals of preventing undue 

discrimination, promoting comparable 

treatment of customers, and increasing 

the accuracy of ATC calculations. 

However, we acknowledge that some 

may currently be relying on the WSPP 

Schedule C agreement in designating 

network resources and that there may be 

disruption if we were to invalidate the 

designations of the existing WSPP 

Schedule C resources. Thus, we exercise 

our discretion not to invalidate existing 

designations of the WSPP Schedule C 

agreements as a result of noncompliance 

with this particular requirement until 

the earlier of the following: (1) The 

expiration of the current term of a 

power purchase agreement or (2) 

redesignation of a previously designated 

WSPP Schedule C resource following a 

period of temporary or indefinite 

termination pursuant to sections 30.2 

and 30.3 of the pro forma OATT. 

Alternatively, parties may voluntarily 

reform the offending contract terms in 

order to preserve their eligibility for 

network service. 

(2) Off-System Resources 

Comments 

1462. Many commenters request 

clarification or reconsideration of the 

information that is required to be 

specified in section 29.2(v) of the pro 

forma OATT in order to designate a 

seller’s choice contract or system sale as 

a network resource. Northwest Parties 

agree with the proposal in the NOPR 

that system sales may be designated by 

providing the control area from which 

the sale is made, transmission 

arrangements, and delivery points to the 

transmission provider’s transmission 

system.870 For system sales, Northwest 


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Parties argue that unit-specific 

information is not needed because such 

sales are, by definition, from a variety of 

resources and, in any event, the 

resource-specific information is 

typically not available to the purchaser. 

This is particularly true, they argue, for 

sales from large hydroelectric systems, 

which are operated as one 

interconnected unit. For purchase 

contracts, they argue that unit-specific 

information is not needed because it is 

provided in the generation 

interconnection agreement to the 

control area where the resource is 

located. Northwest Parties contend that 

not requiring unit-specific information 

for purchase of power, including 

purchases of system power, is consistent 

with the Commission’s description in 

the NOPR of the requirements to 

designate a network resource. 

1463. Pinnacle argues that the Final 

Rule should recognize that the level of 

detail required by section 29.2(v) may 

vary depending on circumstances and 

permit the transmission provider to 

determine the level of information 

necessary for the evaluation of the 

network resource. In some cases, a 

power purchase agreement may, they 

argue, appropriately refer to more 

general information than a specific 

single control area or single source of 

supply. 

1464. In cases where a power 

purchase agreement is being sourced by 

generating units from an external 

control area, Entergy contends on reply 

that simply identifying the control area 

is sufficient for purposes of studying the 

deliverability of that resource. However, 

in cases where the power is sourced by 

generating units internal to the 

transmission provider’s control area, 

Entergy argues that identifying only the 

control area does not provide sufficient 

information to study deliverability. In 

that case, Entergy argues that the 

customer must provide the specific 

information required by section 29.2(v) 

of the pro forma OATT, including the 

location of the specific generating units. 

If such information is not available at 

the time of the network resource 

designation, Entergy argues that the 

customer should still be able to 

designate the agreement as a network 

resource, but that the customer would 

have to confirm resource deliverability 

prior to actually scheduling the service. 

1465. TDU Systems argue in their 

reply comments that specifying the 

control area and the interface over 

which power will enter the transmission 

provider’s transmission system from a 

designated network resource in an 

external control area is sufficient for 

purposes of studying the deliverability 

of that resource. TDU Systems also 

argue that, for competitive reasons, an 

LSE should never be required to identify 

the generator or the transmission zone 

where the generator is located. 

1466. In contrast, EEI requests that the 

Commission modify section 29.2(v) to 

clearly state that the transmission 

provider has the discretion to require 

the network customer to identify the 

location of the generator with more 

specificity than simply specifying the 

control area in which the network 

resource is located, since the location 

will affect the flowgate over which the 

energy will be transmitted. EEI argues 

that it is necessary to narrow the 

location of the source of a power 

purchase to the system of a particular 

transmission owner, rather than a 

control area. PNM-TNMP and Duke also 

support requirements that network 

customers provide more information 

concerning the location of off-system 

network resources and purchase 

agreements so that the transmission 

provider can properly evaluate the 

impact on its system. Duke states that 

Duke Carolinas are now receiving 

requests to designate as network 

resources power purchase agreements 

that list the point of delivery as ‘‘the 

PJM control area’’ or ‘‘into Southern.’’

1467. Dynegy argues in its reply 

comments that the Commission has 

never explained how a transmission 

customer designating a firm LD contract 

as a network resource could ever 

comply with section 29.2 of the pro 

forma OATT, which requires specific 

information about the generation 

resource being designated. Dynegy 

contends that, just like a seller’s choice 

contract, a customer is not entitled to 

any information about particular 

generating assets when entering a firm 

LD purchase contract such as the EEI 

Firm LD Product. As a result, Dynegy 

states that it is unclear how a network 

customer would ever be able to 

legitimately designate such contracts as 

a network resource. 

1468. In order to help ensure that all 

network resources are in fact backed by 

capacity, Dynegy argues that the 

Commission should require 

identification of more than just the 

control area when designating a network 

resource. Dynegy argues that the 

Commission should require the 

generation owner or trading agent for 

the generation to positively verify that 

capacity was sold to the entity 

designating that particular generator as 

a network resource, and that the 

designation is appropriate pursuant to 

the parties’ agreement, as is currently 

required in PJM. 

1469. Because some regions of the 

country determine ATC using a flowbased methodology and other regions 

use a rated path methodology, EEI 

argues that section 29.2(v) should be 

modified to permit transmission 

providers to require a network customer 

to designate the point to which the 

energy is delivered and from which the 

transmission provider will provide 

network service if it is not delivered at 

the generator bus. 

1470. Duke requests that the 

Commission resolve an inconsistency 

between the NOPR’s statement at P 408 

that ‘‘when a network customer is 

designating a system purchase as a new 

network resource, the source 

information required in section 29.2(v) 

should identify that the resource is a 

system purchase and should identify the 

control area from which the power will 

originate,’’ and the statement in the very 

next sentence that a ‘‘power purchase 

agreement that is structured so that a 

network customer cannot specify all of 

the information required by section 

29.2(v) cannot be designated as a 

network resource.’’ Duke notes that 

significantly more information is 

required by section 29.2(v) (unit size, 

VAR capability, operating restrictions, 

variable generating cost for redispatch 

computations, etc.) than the ‘‘control 

area from which the power will 

originate.’’

1471. Morgan Stanley contends that 

the information required in section 

29.2(v) must not disallow designation of 

seller’s choice contracts as network 

resources. They assert that transmission 

providers use security constrained 

economic dispatch under which the 

source of supply in a contract is 

generally irrelevant from a planning or 

operational perspective and is therefore 

not needed. Morgan Stanley also argues 

that, if the underlying network 

customer’s contract permits the seller to 

curtail its dispatch and substitute a 

source from the market, the 

transmission provider would never 

actually know the location where a 

network customer’s power is coming 

from and, thus, it is unclear why the 

specification of that source should be a 

requirement. Therefore, Morgan Stanley 

requests that the Commission consider 

revising 29.2(v) to eliminate the 

inclusion of information that is not 

necessary or make the provision of such 

information required ‘‘to the extent 

practicable.’’

1472. Duke replies that Morgan 

Stanley accurately portrays what 

typically happens under seller’s choice 

contracts, but reaches the wrong 

conclusion about a remedy. Duke argues 

that, if network customers are permitted 


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871 18 CFR 37.6. 872 102 FERC ¶ 61,257 at P 14. 

to designate as network resources 

contracts that may be relatively longterm, but under which the seller has no 

obligation to identify the source of the 

power any sooner than on a day-ahead 

basis, then ATC may be reserved even 

though there is no intent to use it. Duke 

also argues that allowing seller’s choice 

contracts would hamper the 

transmission provider’s ability to plan 

its system. In Duke’s view, it would be 

appropriate to permit a seller’s choice 

contract to be a designated network 

resource at the time transmission 

service is granted for the period such 

transmission service lasts, as at that 

point the customer will have designated 

a source and sink. 

1473. Fayetteville recognizes that 

there are problems related to modeling 

and reliability in contracts for energy 

which do not specify particular units as 

sources, but argues that these problems 

are exactly the same as those that exist 

within any vertically integrated utility 

which names its generation fleet as 

network resources for its native load. 

Commission Determination 

1474. Many comments were received 

with respect to seller’s choice and 

system purchases. Some comments refer 

not only to seller’s choice and system 

purchases, but also to other possible offsystem transactions, including sourcing 

from owned generation located offsystem. We therefore use the term ‘‘offsystem resources’’ here to refer to all 

such resources. 

1475. The existing requirements in 

section 29.2(v) are intended to ensure 

that the network customer designating 

resources on other transmission systems 

provides sufficient information to allow 

the local transmission provider to 

determine the effect on ATC. 

Conversely, network customers should 

not be permitted to designate off-system 

resources which are so vaguely defined 

that the effects on ATC cannot be 

determined. In light of the requests that 

the Commission clarify exactly what 

information must be provided in order 

to designate network resources located 

off-system, and what information 

required by section 29.2(v) must be 

posted on OASIS, we will revise section 

29.2(v) of the pro forma OATT to 

specify exactly what information is 

required. 

1476. As revised by the Final Rule, 

section 29.2(v) of the pro forma OATT 

will require the following information to 

be provided with the request and posted 

on OASIS when designating an offsystem resource: (1) Identification of the 

resource as an off-system resource; (2) 

amount of power to which the customer 

has rights; (3) identification of the 

control area(s) from which the power 

will originate; (4) delivery point(s) to 

the transmission provider’s 

transmission system; and (5) 

transmission arrangements on the 

external transmission system(s). 

Additionally, section 29.2(v) is revised 

to require that the following information 

be provided with such designation, but 

such information must be masked on 

OASIS to prevent the release of 

commercially sensitive information 

including (1) any operating restrictions 

(periods of restricted operation, 

maintenance schedules, minimum 

loading level of resource, normal 

operating level of resource); and, (2) 

approximate variable generating cost 

($/MWH) for redispatch computations. 

Requests to designate off-system 

network resources submitted on or after 

the effective date of this Final Rule must 

include all of the information listed 

above. 

1477. We direct transmission 

providers to develop OASIS 

functionality to (1) allow all of the 

information required for a request to 

designate network resources to be 

provided electronically, (2) mask 

information about operating restrictions 

and generating cost on OASIS, and (3) 

allow for queries of all information 

provided with designation requests in 

accordance with section 37.6 of the 

Commission’s regulations.871 As 

provided in paragraph 385, we also 

direct transmission providers to work in 

conjunction with NAESB to develop 

business practice standards describing 

procedural requirements for submitting 

designations over any new OASIS 

functionality. Transmission providers 

need not implement this new OASIS 

functionality and any related business 

practices until NAESB develops 

appropriate standards. Prior to 

implementation of this new OASIS 

functionality, any information that 

cannot be provided electronically may 

be submitted by transmitting the 

information to the transmission 

provider by telefax or providing the 

information by telephone over the 

transmission provider’s time recorded 

telephone line. 

1478. Duke argues that there is an 

inconsistency between the following 

statements in P 408 of the NOPR: (1) 

‘‘when a network customer is 

designating a system purchase as a new 

network resource, the source 

information required in section 29.2(v) 

should identify that the resource is a 

system purchase and should identify the 

control area from which the power will 

originate’’; and (2) the statement in the 

very next sentence that a ‘‘power 

purchase agreement that is structured so 

that a network customer cannot specify 

all of the information required by 

section 29.2(v) cannot be designated as 

a network resource.’’ We disagree. The 

first statement only provided guidance 

on what could be provided in lieu of the 

source of supply information (as 

required in the last bullet of section 

29.2(v) of the existing pro forma OATT) 

and was not intended to excuse 

customers from providing all of the 

relevant information for an off-system 

purchase other than the specific source 

of supply. However, the revisions to 

section 29.2(v) we adopt in this Final 

Rule remove any confusion. 

1479. We disagree with Dynegy’s 

argument that no firm LD contracts 

would be able to meet the requirements 

for designation. We note that all of the 

information required for off-system 

resources should be available for a 

seller’s choice contract. Even firm LD 

contracts have variable generating costs 

(energy cost) and may have maintenance 

and other operating constraints. If no 

such constraints are contractually 

specified, or if no such constraints are 

relevant to an owned generation 

resource being designated, then that 

should be reflected in the information 

posted on OASIS. 

1480. We reject Dynegy’s request that 

the Commission require additional 

verification by sellers that capacity was 

in fact sold to an entity designating that 

particular generator as a network 

resource and that the network resource 

designation is appropriate pursuant to 

the parties’ agreement. As the 

Commission explained in Illinois 

Power,872 a firm energy purchase need 

not be backed by capacity to qualify as 

a designated network resource. 

1481. We disagree with commenters 

who argue that more specific 

information than the control area must 

be provided with each request to 

designate system purchases or seller’s 

choice contracts as network resources. 

In particular, we disagree with EEI’s and 

Duke’s argument that customers 

designating seller’s choice contracts as 

network resources must be required, on 

a generic basis, to identify the specific 

transmission system, rather than the 

more general control area, in which the 

physical resources are located. EEI 

argues that such specificity is required 

for transmission providers to identify 

the individual flowgates over which the 

power will flow into their system. The 

existing section 29.2(v) of the pro forma 

OATT requires that customers 

designating network resources identify 


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873 In its reply comments, Newmont Mining cites 

(through reference to its own NOI reply comments) 

the statement in H.R. Rep No. 108–65 at 171 (2003) 

that ‘‘[t]his section is intended to be consistent with 

the Commission’s Order No. 888,’’ as well as the 

statement in S. Rep. No. 109–78 at 50 (2005) that 

section 217 ‘‘does not affect the Commission’s 

authority under sections 205 and 206 [of the FPA] 

to ensure that rates are just and reasonable and not 

unduly discriminatory or preferential.’’

874 176 F.3d 1090, 1096 (8th Cir. 1999), cert. 

denied, 528 U.S. 1182 (2000). 

the ‘‘delivery point(s) to the 

transmission provider’s transmission 

system.’’ We agree with Entergy and 

TDU Systems that providing both the 

control area in which off-system 

resources are located as well as the 

delivery point(s) to the transmission 

provider’s transmission system is 

usually sufficiently specific to allow a 

transaction to be evaluated for its effect 

on the ATC of the local transmission 

system. However, we acknowledge 

Duke’s concern about receiving requests 

to designate as network resources 

purchase agreements that list the point 

of delivery as only vague statements 

such as ‘‘the PJM control area’’ or ‘‘into 

Southern.’’ If any transmission provider 

believes that it faces unique 

circumstances that require deviations 

from the pro forma OATT in order to 

allow them to determine the effects of 

designations of network resources on 

ATC, it can, in a filing pursuant to FPA 

section 205, propose terms and 

conditions that it demonstrates are 

consistent with or superior to the pro 

forma OATT. 

1482. Because some regions of the 

country determine ATC using a flowbased methodology and other regions 

use a rated path methodology, EEI 

argues that section 29.2(v) should be 

modified to permit transmission 

providers to require a network customer 

to designate the point to which the 

energy is delivered and from which the 

transmission provider will provide 

network service if it is not delivered at 

the generator bus. It is unclear what 

specific changes EEI is requesting. We 

note that, with respect to off-system 

purchases, section 29.2(v) of the pro 

forma OATT already requires that the 

delivery point(s) to the transmission 

provider’s transmission system be 

included in the description of the 

network resource. 

1483. In response to Entergy’s request, 

we clarify that a customer may not 

designate as a network resource a 

seller’s choice power purchase 

agreement which is sourced by 

generating units internal to the 

transmission provider’s control area, 

since evaluating the effect on ATC 

would be problematic. We disagree with 

Entergy that a customer should be able 

to designate such a resource, even 

without specifying the location of the 

specific generating units, provided that 

the customer’s network service from 

those units is contingent upon 

confirming resource deliverability prior 

to actually scheduling the service, 

because such a policy would still 

significantly obscure the evaluation of 

ATC. If a customer wishes to have a 

choice of resources that are internal to 

the particular transmission provider’s 

control area from which to dispatch 

power, it must designate each of the 

resources as network resources. 

1484. We disagree with Morgan 

Stanley’s unsupported comments that 

the source of supply in a contract is 

irrelevant. We find that location of 

resources is a critical factor to the 

transmission provider’s ATC 

calculations and its ability to model and 

evaluate the proposed network resource, 

regardless of whether the transmission 

providers use security constrained 

economic dispatch. 

(3) Ability To Serve Native Load 

Comments 

1485. Many parties contend that the 

Commission’s policy with regard to the 

qualification of network resources 

affects their ability to serve native load. 

EEI argues that energy purchases are an 

integral part of the resources many 

utilities use to serve their loads, yet 

often such projected energy purchases 

are not under contract until shortly 

before the power is needed. According 

to EEI, the requirement that a purchase 

contract be executed to qualify as a 

network resource jeopardizes the ability 

of such utilities to serve their native 

loads because they will not be able to 

reserve transmission capacity and other 

users may receive all of the ATC before 

their contracts are executed. 

1486. APPA, EEI and Nevada 

Companies argue that restrictions on the 

types of generation and power supply 

arrangements that qualify for network 

service may violate section 217 of the 

FPA. EEI notes that section 217 provides 

that LSEs are entitled to use firm 

transmission rights to deliver the output 

of their generators or purchased energy 

to meet their service obligations to their 

loads. In EEI’s view, section 217 

requires the Commission to exercise its 

authority in a manner that enables LSEs 

to secure firm transmission rights on a 

long term basis for long term power 

supply arrangements made, or 

‘planned,’ to meet such needs and, 

therefore, a requirement that network 

customers and transmission providers 

not reserve transmission capacity to 

serve their network loads and native 

loads unless they either own generation 

or have executed contracts that specify 

the source of the energy is inconsistent 

with section 217. APPA notes that 

section 217 does not distinguish among 

the types of power supply arrangements 

that an LSE must enter into to be 

protected and that section 217(b)(1)(A) 

refers to a broad universe of owned or 

contracted generation that would 

suffice, so long as the power supplies 

are for the purpose of meeting a service 

obligation. 

1487. Newmont Mining disagrees that 

the Commission’s requirements for 

designation of network resources are 

contrary to the new FPA section 

217(b)(2). Newmont Mining argues the 

legislative history of section 217(b)(2) 

shows that it was intended essentially to 

codify Order No. 888 873 and that the 

resource designation requirements do 

not deny LSEs any right to use their 

transmission, but rather prescribe how 

they are to implement that right. 

1488. EEI, Nevada Companies, PNMTNMP and South Carolina E&G on reply 

also argue that the Commission’s 

requirements for eligibility for 

designation as a network resource may 

impermissibly conflict with statemandated procurement plans. EEI and 

South Carolina E&G contend that, by 

imposing restrictions on the ability of 

LSEs to serve their native load, the 

Commission is indirectly asserting 

jurisdiction over state-regulated 

procurement practices, which they 

further argue is prohibited under 

Northern States Power Co. v. FERC.874

1489. Nevada Companies argue that 

the type of contracts that the 

Commission has determined to be 

eligible for qualification as network 

resources tend to be the most expensive. 

They point out that state regulatory 

agencies might determine that other 

types of contracts are more cost-effective 

without unnecessarily jeopardizing 

reliability. Even more troubling, they 

argue, is the problem created when 

transmission providers have peak loads 

that can more effectively be served by 

purchasing power on a short-term 

period (i.e., less than one year). To 

reserve the transmission required to 

serve a needle peak that can occur 

anytime within a four month period 

would require the purchase of 

thousands of megawatt hours of power 

that Nevada Power knows it will not 

need, resulting in a disallowance by the 

Public Utility Commission of Nevada, 

which approves all open positions, 

options and hedges for Nevada Power. 

1490. Nevada Companies contend that 

the network designation process should 

not be changed on systems where the 

process works reasonably well, 


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875 Florida Power Corp, 81 FERC ¶ 61,247 (1997) 

(Florida Power). 

particularly on systems where 

transmission providers are required to 

make significant purchases of power to 

meet their retail loads. Nevada 

Companies argue that the Commission 

should therefore give transmission 

providers the option of instituting a 

reservation-based contract demand 

service similar to that previously 

approved in Florida Power.875

1491. Newmont Mining replies that 

Nevada Companies proposal is not 

similar to the Florida Power proposal or 

other approved contract demand 

network service arrangements, as those 

services were offered at the request of a 

network customer; designed to deal 

with a particular circumstance of the 

network customer; and offered as an 

option to, not as a replacement for, 

standard network integration services. 

Utah Municipals in their reply 

comments agree that utilities should not 

be permitted to unilaterally impose a 

contract demand ‘‘reservation based’’

methodology on its network customers. 

1492. Newmont Mining argues that 

Nevada Companies’ request to maintain 

an open position for a portion of their 

resource portfolio, in accordance with 

their required resource planning 

process, does have some basis, but that 

Nevada Companies’ proposal is not the 

right solution. If the Commission is 

inclined to provide some relief to 

Nevada Companies, Newmont Mining 

argues that such relief should come, if 

at all, only after an investigation of how 

similar problems are handled on other 

systems and that such relief should be 

limited. The limitations Newmont 

Mining suggests include, among other 

things, excusing Nevada Companies 

from the requirement, if at all, only to 

the extent that a specific open portfolio 

position is contained in a resource plan 

approved in accordance with applicable 

law; requiring that the reservation be 

posted on OASIS; not granting a 

reservation to Nevada Companies over a 

competing application for network 

service by a potential network customer 

that actually has a designated network 

resource; and permitting other network 

customers to hold similar open 

positions. 

Commission Determination 

1493. We generally disagree with 

arguments that the Commission’s 

restrictions on the designation of 

network resources may violate section 

217 of the FPA. Congress did not require 

that LSEs be able to take transmission 

service without limitations of any kind 

in order to serve their native load, and 

nothing in section 217 suggests that 

LSEs should not be required to comply 

with reasonable requirements that are 

necessary to prevent undue 

discrimination and maintain a reliable 

transmission system. The conditions 

that have been established for taking 

network transmission service are 

reasonable and support these goals, and 

we therefore disagree that such 

conditions are inconsistent with the 

requirements of section 217. 

Furthermore, as Newmont Mining 

points out, the legislative history of 

section 217(b)(2) supports the 

interpretation that section 217 was 

intended to be consistent with the 

Commission’s authority under sections 

205 and 206 of the FPA to ensure that 

rates are just and reasonable and not 

unduly discriminatory or preferential, 

under which the designation 

requirements in Order No. 888 were 

adopted. 

1494. We also disagree with 

commenter arguments that the 

Commission’s requirements for 

eligibility for designation as a network 

resource impermissibly conflicts with 

state-mandated procurement plans. We 

point out that, with the exception of 

some clarifications on the types of LD 

provisions that are acceptable in 

designated firm LD products and what 

information a customer designating a 

system purchase or a seller’s choice 

contract must provide, the requirements 

for designation of network resources are 

not new. Order No. 888 has long 

required that contracts be executed and 

imposed reasonable restrictions on the 

types of resources that may be 

designated as network resources. 

1495. To the extent that individual 

transmission providers have unique 

circumstances or needs that justify a 

variation from the pro forma OATT, 

those parties can request such a 

variation and explain why their 

proposed variation is consistent with or 

superior to the requirements of the pro 

forma OATT in a section 205 filing. In 

particular, Nevada Companies’ request 

for approval of a contract demand 

service in order to address certain issues 

presented by their unique situation 

would properly be made in the context 

of a section 205 filing requesting a 

deviation from the pro forma OATT. We 

agree with Newmont Mining and Utah 

Municipals that approved variations, if 

any, must be applied on a comparable 

basis to both the transmission provider’s 

merchant function and the other 

network customers. 

(4) General 

Comments 

1496. A number of commenters raised 

other general concerns regarding the 

designation of network resources. TAPS 

requests that the Commission clarify 

that conditional firm transmission 

service is sufficiently firm to meet the 

requirement that third-party 

transmission arrangements to deliver a 

designated purchase to the network be 

noninterruptible. TAPS also requests 

that the Commission provide for 

designation of network resources within 

the control area on a conditional firm 

basis. 

1497. In its reply comments, South 

Carolina E&G request clarification of the 

content and process of making 

information postings in accordance with 

section 29.2 of the pro forma OATT. 

South Carolina E&G argues that, taken 

literally, section 29.2 requires that 

everything in an application for network 

service be posted. South Carolina E&G 

contends, however, that the contents of 

an application do not fit on OASIS as 

currently configured, and that making 

such information available on OASIS is 

not necessary for the Commission’s 

purposes, particularly given the 

Commission’s representations in favor 

of preserving the integrity of customer 

confidential information. South 

Carolina E&G suggests the Commission 

require only the following information 

to be posted on OASIS: identification of 

the service type as ‘‘network’’; 

identification of the source by name of 

the generator or system; identification of 

the sink by name of the network 

customer’s load; identification of the 

point of receipt by specification of the 

interface at which the network customer 

intends to deliver to the resource into 

the transmission provider’s 

transmission area; and identification of 

the point of delivery and sink. 

1498. South Carolina E&G also 

requests clarification on how designated 

network resources are to be posted. 

South Carolina E&G asks, for instance, 

whether the Commission expects 

transmission providers to develop an 

OASIS template that network customers 

can update, as necessary, for network 

resources to simply be posted in PDF 

format, or be accomplished via the 

comment section of an OASIS 

reservation. South Carolina E&G argues 

that posting via the comment section of 

OASIS allows for operational ease, but 

provides limited transparency and 

includes administrative challenges due 

to character limitations and formatting 

constraints. Alternatively, South 

Carolina E&G argues, new functionality 

on OASIS that allows customers to post, 


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876See 18 CFR 37.6(a). 

877See, e.g., Entergy Services, Inc., 105 FERC 

¶ 61,318 (2003), reh’g denied in relevant part, 109 

FERC ¶ 61,216 (2004). 

modify and update network resources 

would satisfy the Commission’s 

requirements, but would involve added 

costs and time. 

1499. TranServ seeks clarification as 

to the minimum term, if any, that the 

transmission provider must honor for 

designation of new network resources. 

TranServ requests that network 

resources be allowed to be designated 

for the same minimum time periods 

used for firm point-to-point service, i.e., 

daily or hourly service. Conversely, 

South Carolina E&G argues in its reply 

comments that requiring transmission 

providers to update their list of 

designated network resources on an 

hourly basis is too burdensome. South 

Carolina E&G requests that the 

Commission allow alternative methods 

of designating network resources on a 

short-term basis, such as adding 

comments to the appropriate comment 

field on either eTags or OASIS 

reservations. 

1500. TDU Systems argue that the 

designation of network resources 

(explicit or implicit) by some 

transmission providers is automatic, 

while network customers are required to 

pay for elaborate studies of every 

conceivable path affected by the 

addition of the resource. TDU Systems 

request that the Commission clarify that 

the process of network resource 

designation should be the same for all 

network users. 

1501. APPA, Fayetteville, NCPA, 

Northwest Parties, TAPS, and 

Wolverine request that clarifications 

made to the Commission’s policy for 

qualification as a network resource 

apply prospectively and/or that 

sufficient time be allowed after the 

adoption of the Final Rule such that the 

necessary products, information systems 

and business practices can be 

developed. Such commenters contend 

that the designated network resources 

they currently rely upon were acquired 

and designated consistent with prior 

Commission precedent, so that changes 

to the network resource criteria 

established in this proceeding should 

not invalidate the continued use of such 

resources. Because there may be many 

existing designated network resources 

that do not meet the standards that the 

Commission eventually sets, Duke 

suggests on reply that the Commission 

may need to permit existing contractual 

designated network resources that do 

not qualify under the new standard to 

retain their designated status until the 

earlier of the expiration data of the 

transaction or the expiration date of any 

necessary transmission service 

supporting that network resource. 

1502. In its reply comments, Dynegy 

disagrees with request to grandfather 

existing designated network resources, 

and argues that the Commission’s 

holding in Dynegy was erroneous and 

should be remedied in its entirety, 

without the creation of yet another class 

of grandfathered entities. 

Commission Determination 

1503. The Commission agrees with 

TAPS that firm point-to-point 

transmission service provided on a 

conditional firm basis is sufficiently 

firm to be used for transmission to 

import a designated network resource. 

Firm point-to-point transmission service 

provided on a conditional firm basis 

meets the existing requirement that 

transmission arrangements in other 

control areas delivering power 

purchases designated as network 

resources to the network customer’s 

transmission provider must not be 

interruptible for economic reasons, as 

explained further in section III.F of this 

Final Rule. With respect to TAPS’

second request for clarification to allow 

for designation of network resources 

within the control area on a conditionalfirm basis, we note that such 

designation of network resources within 

the control area will not be allowed, as 

discussed further in section III.F. 

1504. In response to South Carolina 

E&G’s request, we reiterate that not all 

of the information required by section 

29.2 of the pro forma OATT for 

designation of a network resource will 

be made publicly available on OASIS. 

As discussed above, information about 

operating restrictions and generating 

cost will be masked to protect 

commercially sensitive information. 

South Carolina E&G has also requested 

clarification of the Commission’s intent 

with respect to how designated network 

resource information is posted. Our 

existing regulations specify the view, 

download, and query requirements for 

information posted regarding network 

resource designations.876 The details of 

how those informational postings are 

accomplished are best left to be 

determined as part of the NAESB 

standards development process. 

1505. TranServ requests that the 

Commission clarify the minimum term, 

if any, that a transmission provider must 

honor for designations of new network 

resources. We agree with TranServ that 

the minimum term should be the same 

as the minimum time period used for 

firm point-to-point service (i.e., daily), 

unless otherwise demonstrated by the 

transmission provider and approved by 

the Commission.877

1506. In response to TDU Systems’

request for clarification that the process 

of network resource designation should 

be the same for all users, we note that 

section 28.2 of the pro forma OATT 

already provides that ‘‘[t]he 

Transmission Provider, on behalf of its 

Native Load Customers, shall be 

required to designate resources and 

loads in the same manner as any 

Network Customer under Part III of this 

Tariff.’’ We encourage parties to utilize 

the Commission’s Enforcement Hotline 

to report suspected abused of this 

process. 

b. Documentation for Network 

Resources 

NOPR Proposal 

1507. In the NOPR, the Commission 

noted that transmission providers are 

responsible for verifying that the 

network customer has provided all the 

information required in section 29.2, but 

that transmission providers are not 

responsible for verifying that the 

generating units and power purchase 

agreements network customers 

designate as network resources satisfy 

the requirements in sections 30.1 and 

30.7 of the pro forma OATT. However, 

the Commission also explained that the 

transmission provider continues to have 

the responsibility to verify that thirdparty transmission arrangements to 

deliver the purchase to the transmission 

provider’s system are firm. 

1508. The Commission proposed to 

require the transmission provider’s 

merchant function as well as network 

customers to include a statement with 

each application for network service or 

to designate a new network resource 

that attests that, for each network 

resource identified in the application for 

service, (1) the transmission customer 

owns or has committed to purchase the 

designated network resource, and (2) the 

designated network resource comports 

with the requirements for designated 

network resources. 

1509. If the network customer does 

not include an attestation when it 

confirms its request, the Commission 

proposed that the transmission provider 

will notify the network customer within 

15 days of confirmation that its request 

is deficient and that, wherever possible, 

the transmission provider will attempt 

to remedy deficiencies in the request 

through informal communications with 

the network customer. If such efforts are 

unsuccessful, the Commission further 


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878E.g., Ameren, Entegra, Pinnacle, Public Power 

Council, and Southern. 879See Investigation of Terms and Conditions of 

Public Utility Market-Based Rate Authorizations, 

105 FERC ¶ 61,218 (2003). 

880E.g., Ameren, EEI, Suez Energy NA, Nevada 

Companies, and Utah Municipals. 

881E.g., Ameren, Duke Reply, Entergy, and 

Pinnacle. 

882E.g., EEI, TDU Systems, Indianapolis Power 

Reply, and South Carolina E&G Reply. 

883E.g., EEI and Indianapolis Power Reply. 

proposed that the status of the request 

on OASIS will be changed to 

‘‘retracted’’ and the network customer’s 

request will be terminated without 

prejudice to the network customer 

submitting a new request that includes 

the required attestation, after which the 

network customer will be assigned a 

new priority consistent with the date of 

the new request. 

1510. In the event that the 

transmission provider or any network 

customer designates a network resource 

that it does not own or has not 

committed to purchase, or that does not 

otherwise comport with the 

requirements for designated network 

resources, the Commission proposed 

that it will deem the network customer 

to be in violation of the pro forma 

OATT and will consider assessing civil 

penalties on a case-by-case basis 

consistent with the Commission’s Policy 

Statement on Enforcement. The 

Commission encouraged the 

transmission provider and other market 

participants to use the Commission’s 

Enforcement Hotline to report instances 

when they believe a network customer 

has designated as a network resource a 

resource that does not meet the criteria 

for network resources. 

Comments 

1511. Several commenters support the 

overall proposed changes involving 

attestation requirements, claiming the 

proposal should help to eliminate 

abuse, including the practice of some 

utilities denying transmission requests 

in order to accommodate its merchant 

function’s plans to engage in future 

short-term purchases to serve native 

load.878 Entegra explicitly supports the 

Commission’s proposal to treat failures 

to comply as violations of the pro forma 

OATT subject to enforcement. Pinnacle 

notes that customers should make such 

attestations in good faith, such that an 

inadvertent error or omission would not 

automatically result in recourse to a 

legal remedy if it can be corrected 

without adverse impacts. 

1512. Dynegy argues in its reply 

comments that transmission customers 

who knowingly provide false or 

inaccurate information in their network 

resource designations not only 

jeopardize reliability, but are essentially 

engaging in theft. Dynegy argues that 

such parties should be subject to the 

sanctions and penalties under the 

Market Behavior Rule,879 including 

revocation of the violator’s market-based 

rate authority. APPA and TAPS argue 

that the new attestation requirements 

should be consistently applied to all 

network customers, including the 

transmission provider’s merchant 

function and affiliates. 

1513. Several commenters support the 

Commission’s determination that 

transmission providers are not required 

to independently verify the accuracy of 

an application for network service.880

Some commenters request that the 

Commission clarify that transmission 

providers or transmission owners can 

voluntarily seek information which 

verifies that contractual terms meet the 

requirements in section 30.1 and 30.7 of 

the pro forma OATT.881 In its reply 

comments, Duke argues that, without 

the ability to request the contracts 

supporting the compliance with the 

requirement that the designated network 

resources are firm enough, the 

Commission may not have authority to 

require that the network customer 

support its designation in situations 

where the network customer is 

nonjurisdictional. 

1514. Pinnacle disagrees with the 

NOPR proposal that transmission 

providers should continue to be 

responsible for verifying the firmness of 

the network customers’ transmission 

arrangements on other systems. Instead, 

Pinnacle contends that the transmission 

customer should have the obligation to 

ensure that their transmission 

arrangements meet the requirements 

needed to ensure that their resources 

qualify as designated network resources. 

In its reply comments, Detroit Edison 

also requests that the Commission 

require proof that network customers 

have obtained the requisite transmission 

service on external systems. 

1515. Dynegy, in its reply comments, 

requests that network resource 

information and validity of designation 

be verified not only by the designating 

customer, but also by the seller or owner 

of the generation, in order to help 

ensure that all network resources are in 

fact backed by capacity. Entegra 

similarly suggests that the Commission 

require that entities designating network 

resources make periodic OASIS postings 

that will permit verification that the 

entity designating a generating facility 

as a network resource actually has rights 

to power from that facility. 

1516. EEI and Entergy allege that the 

Commission’s NOPR attestation 

proposal may have unintended 

consequences. Some commenters 

contend that the gap between the 

Commission’s interpretation of the 

qualifications of network resources and 

current procurement practices creates a 

significant possibility that, if the 

Commission enforces its policies, it 

could cause substantial disruptions of 

service to network and native loads, 

reduce supply options, or expose 

network customers and transmission 

providers to increased liability.882 EEI 

asserts that this is because a significant 

number of network customers and 

transmission providers are serving their 

network loads and native loads using 

resources, particularly power purchase 

contracts, that may not meet the 

Commission’s requirement for 

designation as network resources. Some 

commenters request that the 

Commission engage in a comprehensive 

review of power purchase practices 

before implementing its proposed 

attestation requirement, and apply any 

change in policies only to power 

purchases entered into after the effective 

date of the Final Rule and after the 

industry has had time to develop new 

products that meet the Commission’s 

requirements.883

1517. Entegra replies that the 

expressed concern about the attestation 

requirement by EEI is puzzling and 

troubling, because the NOPR did not 

propose to change the current 

requirements of the pro forma OATT 

regarding the qualification of network 

resources. Entegra argues that the 

widespread non-compliance alleged by 

EEI makes adoption of an attestation 

requirement more important and that 

EEI’s allegations may, at most, suggest 

that the Commission consider some sort 

of amnesty for network customers and 

transmission providers willing to selfreport and commit to full compliance 

with the network resource rules going 

forward. 

1518. To ensure that network 

customers can submit requests for new 

network service without a final, 

executed contract, Entergy requests that 

an attestation to designate a new 

network resource should not be required 

until the service request is confirmed. If 

the request is pre-confirmed, Entergy 

suggests that the attestation should be 

provided at the time the request is 

submitted. 

1519. SPP requests that the 

Commission not require it to police the 

additional restrictions on the 

designation of network resources 

proposed in the NOPR. SPP states that 

it has neither the data nor the personnel 


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884E.g., MISO, Indianapolis Power Reply, and 

Detroit Edison Reply. 

885See supra note 75. 

886Policy Statement on Enforcement at P 13. 

887 Id. at P 20. 

888 Id. 

889 Investigation of Terms and Conditions of 

Public Utility Market-Based Rate Authorizations, 

105 FERC ¶ 61,218 (2003). 

necessary to perform this function and 

that the Commission should rely on 

network customer verification, subject 

to Commission audits. TranServ 

suggests that the exact nature of how the 

customer would make the newly 

required attestation, as well as the 

treatment of OASIS requests failing to 

provide the required attestation, should 

be determined in the NAESB forum at 

the time when the technical 

requirements for processing network 

service requests on OASIS are 

established. 

1520. Several commenters request 

that the Commission amend section 30.2 

of the pro forma OATT to require 

network customers that designate 

network resources in an external control 

area also provide a certification from 

that control area’s administrator that the 

resource being designated is not 

counted as a designated resource for 

another load on or off of the system.884

TDU Systems disagree, arguing on reply 

that the Commission should not require 

these types of certifications. TDU 

Systems recommend, in the alternative, 

that LSEs on multiple systems should 

not have to undesignate network 

resources to serve off-system load, 

which would eliminate the need for 

such control area certification for such 

transactions. TDU Systems also argues 

that, in the absence of any evidence of 

abuse, the Commission should not 

further complicate a process that most 

market participants would agree is 

already overly complicated and 

burdensome. 

Commission Determination 

1521. The Commission adopts the 

NOPR proposal that transmission 

providers continue to be responsible for 

verifying that third-party transmission 

arrangements to deliver the purchase to 

the transmission provider’s system are 

firm, but that transmission providers are 

not responsible for verifying that the 

generating units and power purchase 

agreements network customers 

designate as network resources satisfy 

the requirements in sections 30.1 and 

30.7 of the pro forma OATT. We also 

adopt the proposal to require both the 

transmission provider’s merchant 

function and network customers to 

include a statement with each 

application for network service or to 

designate a new network resource that 

attests, for each network resource 

identified, that (1) the transmission 

customer owns or has committed to 

purchase the designated network 

resource and (2) the designated network 

resource comports with the 

requirements for designated network 

resources. The network customer should 

include this attestation in the 

customer’s comment section of the 

request when it confirms the request on 

OASIS. 

1522. If the network customer does 

not include the attestation when it 

confirms the request, the transmission 

provider must notify the network 

customer within 15 days of 

confirmation that its request is deficient, 

in accordance with the procedures in 

section 29.2 of the pro forma OATT. 

Whenever possible, the transmission 

provider shall attempt to remedy 

deficiencies in the request through 

informal communications with the 

network customer. If such efforts are 

unsuccessful, the transmission provider 

shall terminate the network customer’s 

request and change the status of the 

request on OASIS to ‘‘retracted.’’ This 

termination shall be without prejudice 

to the network customer submitting a 

new request that includes the required 

attestation. The network customer shall 

be assigned a new priority consistent 

with the date of the new request. 

1523. In the event that the 

transmission provider or any other 

network customer designates a network 

resource that it does not own or has not 

committed to purchase or that does not 

comport with the requirements for 

designated network resources, we will 

deem the network customer to be in 

violation of the pro forma OATT and 

will consider assessing civil penalties 

on a case-by-case basis, consistent with 

the Commission’s Policy Statement on 

Enforcement.885 We encourage the 

transmission provider and other market 

participants to use the Commission’s 

Enforcement Hotline to report instances 

where they believe a network resource 

has been designated that does not meet 

the Commission’s requirements. 

1524. In response to Pinnacle’s 

request that an inadvertent error or 

omission should not automatically 

result in a penalty if it can be corrected 

without adverse impacts, we reiterate 

the policy established in the 

Commission’s Policy Statement on 

Enforcement that enforcement actions 

will not be imposed ‘‘automatically.’’

Enforcement actions are instead 

considered on a case-by-case basis after 

consideration of a number of factors 

which may result in penalties being 

reduced or eliminated.886 Among the 

many factors to be considered pursuant 

to the Policy Statement on Enforcement 

is whether the violation is willful.887 At 

the same time, consideration is 

provided for other factors that may 

weigh for assessing civil penalties, even 

in circumstances of inadvertent 

violations. For instance, the 

Commission considers whether the 

violator has a history of violations and 

whether the actions were recklessly or 

deliberately indifferent to the results.888

While enforcement actions will not be 

automatic, and the inadvertence of a 

violation would be a consideration 

when determining what, if any, penalty 

to impose, there may be some instances 

where inadvertent violations would be 

found, after consideration as established 

in the Policy Statement on Enforcement, 

to warrant a penalty. 

1525. Dynegy also requests that 

transmission customers who knowingly 

provide false or inaccurate information 

in their network resource designations 

be subject to the sanctions and penalties 

under the Market Behavior Rules,889

including revocation of the violator’s 

market-based rate authority. We 

reiterate that violations will be dealt 

with on a case-by-case basis in 

accordance with the Policy Statement 

on Enforcement. 

1526. We reject requests to allow the 

transmission provider to voluntarily 

seek information which verifies that 

contractual terms meet the requirements 

in sections 30.1 and 30.7 of the pro 

forma OATT. Allowing transmission 

providers to verify terms and conditions 

of power purchase agreements would 

put transmission providers in the 

position of interpreting contracts and 

accepting or rejecting designations 

based on their interpretations. We 

believe such authority is unnecessary in 

light of the new attestation requirements 

and that instances of non-compliance 

are better handled by the Commission’s 

enforcement staff in the context of 

audits and Enforcement Hotline reports. 

This applies equally to jurisdictional 

and nonjurisdictional customers. Every 

transmission customer must satisfy the 

requirements of the transmission 

provider’s OATT in order to take 

service. The Commission thus has 

authority to require that all network 

customers support their designations. 

1527. We disagree with Pinnacle’s 

argument that transmission providers 

should not be responsible for verifying 

the firmness of the network customer’s 

transmission arrangements on other 

systems. We find that having 


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890Order No. 888–B at 62,093. 

891The general term ‘‘undesignation’’ refers to 

both temporary terminations and indefinite 

terminations of network resource status, as 

discussed below. 

transmission providers verify firmness 

of such transmission arrangements 

provides a significant benefit to the 

system and is not unduly burdensome. 

The confirmation or lack thereof of 

service on the third-party’s system 

should be readily available on OASIS. If 

firm third-party service is not confirmed 

in OASIS, the transmission provider 

should attempt to remedy any 

information deficiency in the request 

through informal communications with 

the network customer. If such efforts are 

unsuccessful, the transmission provider 

should find the request to designate the 

network resource deficient. Because this 

information is available on OASIS, we 

disagree with Detroit Edison’s request 

that the Commission require proof that 

customers have obtained requisite 

transmission service on external 

systems. 

1528. We also disagree with SPP’s 

argument that it should not be required 

to police the additional restrictions on 

the designation of network resources, 

since it has neither the data nor the 

personnel necessary to perform this 

function. The only ‘‘additional’’

restrictions that the transmission 

provider is called upon to police is that 

network customers submit the 

appropriate attestations when 

requesting designation of a network 

resource, which places a particularly 

small burden on the transmission 

provider. We also do not expect the 

requirement that transmission providers 

verify the firmness of the network 

customer’s transmission arrangements 

on other transmission systems to require 

any additional data or personnel. 

1529. We reject Dynegy’s request that 

the validity of network resource 

designations be verified not only by the 

designating customer, but also by the 

seller or owner of the generation, in 

order to help ensure that all network 

resources are in fact backed by capacity. 

Similarly, we deny Entegra’s request 

that the customer be required to make 

additional, periodic OASIS postings to 

demonstrate that it has rights to the 

power from a designated resource. We 

find that such additional verifications 

are unnecessary in light of the new 

attestation requirements. 

1530. With regard to arguments that 

requiring an attestation may disrupt 

service, the alleged confusion over the 

Commission’s requirements for 

designation of network resources seems 

primarily concerned with whether the 

EEI Firm LD Product and similar 

products were eligible to be designated 

as network resources and whether 

certain resources can be designated both 

to serve native load and other network 

customers. As we have addressed both 

of these questions above, we believe that 

many of the concerns about the 

attestation requirement are resolved. 

Commenters have not supported claims 

that the attestation requirement will be 

either burdensome or that the 

requirement will require substantial 

time to comply. As noted above, the 

minimal additional network resource 

designation requirements impose in this 

Final Rule beyond the existing 

requirements are not expected to be 

unduly burdensome. While exceptions 

may be appropriate in cases of 

legitimate emergencies, we disagree 

with the implication that a customer 

should be granted general flexibility to 

designate a network resource that 

otherwise may not be eligible. 

1531. In response to Entergy’s request, 

we agree that attestations will not be 

required to be submitted until the 

service request is confirmed. However, 

if the request is pre-confirmed, we agree 

that the attestation must be provided at 

the time the request is submitted. 

1532. In response to TranServ’s 

request that the exact nature of how the 

customer would make an attestation 

should be determined in the NAESB 

forum, we note that the contents and the 

specific information that is required to 

be provided with the attestation are 

specified in the pro forma OATT, and 

we are requiring that the attestation be 

submitted through OASIS with each 

request to designate a new network 

resource. The appropriate subject for 

transmission providers to coordinate 

with NAESB to resolve is limited to the 

appropriate formatting of such 

information to be provided in OASIS. In 

response to TranServ’s request that 

NAESB should also determine the 

treatment of OASIS requests where the 

customer fails to provide the necessary 

attestation, we point out that we have 

already directed that such requests are 

to be found deficient by the 

transmission provider and treated in 

accordance with the procedures in 

section 29.2 of the pro forma OATT. 

1533. We reject requests to require 

network customers designating network 

resources in an external control area to 

provide certification from that control 

area’s administrator that the resource 

being designated is not counted as a 

designated resource for another load on 

or off the system. We find that, in 

absence of any evidence that the 

Commission’s new attestation 

requirements will be insufficient, this 

requested verification appears 

unnecessary. 

c. Undesignation of Network Resources 

1534. Section 28.2 of the pro forma 

OATT requires the transmission 

provider, on behalf of its native load 

customers, to designate resources and 

loads in the same manner as any 

network customer under Part III of the 

pro forma OATT (Network Integration 

Transmission Service). The information 

provided by the transmission provider 

must be consistent with the information 

it uses to calculate ATC. Section 30.3 of 

the pro forma OATT previously allowed 

the network customer to terminate the 

designation of all or part of a generating 

resource as a network resource at any 

time, but stated that the network 

customer should provide notification to 

the transmission provider as soon as 

reasonably practicable. 

1535. In Order No. 888–B, the 

Commission clarified that the pro forma 

OATT allows network customers to 

designate network resources over 

shorter time periods. The Commission 

indicated that a network customer that 

seeks to engage in firm sales from its 

currently designated network resources 

may terminate the generating resource 

(or a portion of it) as a network resource 

pursuant to section 30.3 of the pro 

forma OATT and request that, as set 

forth in section 29 of the pro forma 

OATT, the same generation resource be 

designated as a network resource 

effective with the end of its power 

sale.890

NOPR Proposal 

1536. In the NOPR the Commission 

proposed to continue to allow network 

customers to ‘‘undesignate’’ 891 a portion 

of their network resources on a shortterm basis to make off-system sales. The 

Commission reiterated that a network 

customer may redesignate the resource 

by making a request to designate a new 

network resource. Additionally, the 

Commission reiterated that the 

transmission provider and all network 

customers must designate their network 

resources and are prohibited from 

making firm third-party sales from 

designated network resources. The 

Commission stated that, to the extent 

the transmission provider or a network 

customer wants to make a firm sale from 

a network resource, it must undesignate 

the resource pursuant to section 30.3 of 

the pro forma OATT. The network 

customer, including the transmission 

provider itself, could request to 

redesignate the resource by making a 

request to designate a new network 

resource pursuant to section 30.2 of the 

pro forma OATT. 


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892 18 CFR 37.6. 

893E.g., Duke, EEI, Entergy, Exelon, MDEA Reply, 

Northwest Parties, Pinnacle, Progress Energy, South 

Carolina E&G Reply, Southern, TDU Systems Reply, 

TranServ, and WSPP Reply. 

894E.g., Duke, EEI, Entergy, Progress Energy, 

South Carolina E&G Reply, and TranServ. 

1537. The Commission also sought 

comment on the amount of time prior to 

operation that the transmission provider 

and other network customers should be 

required to terminate a network 

resource to ensure that the appropriate 

set of network resources are included in 

the ATC calculation. 

(1) Overview 

Comments 

1538. Most commenters appear to 

support the Commission’s proposal to 

continue to allow network customers to 

undesignate a portion of their network 

resources on a short-term basis to make 

off-system sales. However, many 

commenters request clarification that a 

temporary undesignation will not cause 

them to forfeit their rights to 

transmission priority or ATC for any 

other time period. Several commenters 

also request that formal undesignations 

not be required or that the process not 

be burdensome. A wide range of 

comments were received in response to 

the Commission’s request for comments 

on the amount of time prior to operation 

that the transmission provider and other 

network customers should be required 

to terminate a network resource to 

ensure that the appropriate set of 

network resources are included in the 

ATC calculation. 

Commission Determination 

1539. The Commission generally 

adopts the NOPR proposal to continue 

to require network customers and the 

transmission provider’s merchant 

function to undesignate network 

resources or portions thereof in order to 

make certain firm, third-party sales from 

those resources. In particular, network 

customers and the transmission 

provider’s merchant function may only 

enter into a third-party power sale from 

a designated network resource if the 

third-party power purchase agreement 

allows the seller to interrupt power 

sales to the third party in order to serve 

the designated network load. Such 

interruption must be permitted without 

penalty, to avoid imposing financial 

incentives that compete with the 

network resource’s obligation to serve 

its network load. 

1540. We clarify that requests to 

undesignate network resources that are 

submitted concurrently with a request 

to redesignate those network resources 

at a specific point in time shall be 

considered temporary terminations. 

Conversely, requests to undesignate 

network resources submitted without 

any concurrent request to redesignate 

those network resources shall be 

considered a request for indefinite 

termination of those network resources. 

1541. We direct transmission 

providers to develop OASIS 

functionality and, working through 

NAESB, business practice standards 

describing the procedural requirements 

for submitting both temporary and 

indefinite terminations of network 

resources, to allow network customers 

to provide all required information for 

such terminations. Such OASIS 

functionality should allow for electronic 

submittal of the type of termination 

(temporary or indefinite), the effective 

date and time of the termination, and 

identification and capacity of 

resource(s) or portions thereof to be 

terminated. For temporary terminations, 

such OASIS functionality should also 

allow for electronic submittal of (1) 

effective date and time of redesignation, 

following the period of temporary 

termination; (2) information and 

attestation for redesignating the network 

resource following the temporary 

termination, in accordance with section 

30.2 of the pro forma OATT; and (3) 

identification of any related 

transmission service requests to be 

evaluated concomitantly with the 

request for temporary termination. In 

response to TranServ’s request, we 

clarify that the request for temporary 

termination of the resource and the 

requests for the related transmission 

service identified in item (3), if any, 

should be evaluated as a single request, 

and approved or disapproved as such. 

We specifically direct transmission 

providers, working through NAESB, to 

develop business standards describing 

the procedures for submitting and 

processing requests for concomitant 

evaluations of transmission requests and 

temporary terminations. When 

processing such requests, the evaluation 

of the transmission service requests 

identified in item (3) should take into 

account the undesignation of the 

network resources identified in the 

request for termination. However, the 

evaluation of the transmission service 

requests in item (3) should be processed 

taking proper account of all competing 

transmission service requests of higher 

priority. 

1542. Consistent with the 

requirements for requests for 

designation of new network resources, 

the new OASIS functionality should 

also allow for queries of requests to 

undesignate and redesignate network 

resources. In accordance with section 

37.6 of the Commission’s regulations,892

such requests must be able to be queried 

by the publicly available information 

posted on OASIS. 

1543. Transmission providers need 

not implement this new OASIS 

functionality and any related business 

practices until NAESB develops 

appropriate standards. Prior to 

implementation of this new OASIS 

functionality, requests for temporary or 

indefinite terminations of network 

resources may be submitted by 

transmitting the required information to 

the transmission provider by telefax or 

providing the information by telephone 

over the transmission provider’s time 

recorded telephone line. 

(2) Risk to ATC Rights 

Comments 

1544. Most commenters request 

clarification that a temporary 

undesignation of a network resource 

does not constitute a forfeiture of 

priority followed by a new request to 

designate the network resource, or 

otherwise put in jeopardy the ATC 

associated with the designation of that 

resource for any period other than the 

period of undesignation.893 Several 

commenters argue that virtually no 

network customers will ever make a 

firm third-party sale if they are forced to 

reapply for transmission service after a 

period of undesignation of their 

resource, since they would run the risk 

of losing the ATC associated with the 

resource.894 EEI and Entergy contend 

that the result of such a policy would be 

that the industry would no longer be 

able to take advantage of the diversity of 

peak loads to make firm sales and 

purchases, and an almost immediate 

shortage of firm energy sources to serve 

network and native loads. Duke argues 

that the approach of not compelling 

network customers to risk losing the 

ATC associated with their designated 

resources beyond the period that the 

resource is designated would be the 

comparable approach vis-a`-vis point-topoint customers seeking to temporarily 

redirect their service. 

1545. Southern argues that to treat a 

redesignation as an entirely new 

application for network resource 

designation would appear to depart 

from existing tariff requirements and 

unnecessarily limit the reliability of 

network customers’ service. It also 

argues that such an approach would be 

in contravention with section 217(b)(4) 

of the FPA, which directs the 


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895See, e.g., Order No. 2003 at P 118, 744. 

Commission to act in a manner that 

facilitates the planning and expansion 

of facilities to meet the reasonable needs 

of LSEs to satisfy the service obligations 

of the LSEs. Southern contends that the 

NOPR proposal would create 

administrative burdens on transmission 

providers, potentially treat network 

service as an inferior product to long 

term point-to-point transmission 

service, and introduce a substantial 

deterrent against optimization of 

network resources by network 

customers. 

1546. On the other hand, Great 

Northern initially requests that ATC not 

be set aside for a former network 

resource in anticipation that it might be 

designated as a network resource at 

some time in the future. In order to 

ensure comparable treatment for all 

transmission service customers, Great 

Northern argues, the Commission 

should place new requests to designate 

network resources at the end of the 

transmission queue, regardless of the 

prior designation of those resources. 

Great Northern clarifies on reply that, 

while ATC should not be set aside for 

former network resources in 

anticipation that it might be designated 

as a network resource at some 

unspecified time in the future, it has no 

objection to setting aside ATC to be 

used by a formerly designated network 

resource after a temporary, specified 

period of undesignation such as one 

month or one season. 

1547. NorthWestern, in its reply 

comments, disagrees with Great 

Northern’s initial comments that new 

designations be placed at the end of 

transmission service queue regardless of 

the prior designation of those resources. 

NorthWestern argues that such a policy 

would unduly discriminate against the 

network customer who is paying for the 

use of the entire transmission system 

and grant an undue preference to the 

point-to-point customer. NorthWestern 

also argues that the proposal that ATC 

not be set aside for an undesignated 

network resource appears to conflict 

with the Commission’s standard 

interconnection procedures for large 

and small generators. Once all upgrades 

specified through the interconnection 

process have been installed, 

NorthWestern contends that the 

generator can be specified as a network 

resource by any customer, at the time of 

commercial operation for the generator 

or at any time in the future. 

1548. TAPS appears to support a 

requirement that transmission 

customers get back in the queue when 

re-designating resources, so long as the 

rules apply to transmission providers as 

well as network customers. 

Commission Determination 

1549. In response to the many 

requests and comments, we clarify that 

a request for termination of a network 

resource that is concurrently paired 

with a request to redesignate that 

resource at a specific point in time will 

not result in the network customer 

permanently forfeiting rights to use that 

resource as a designated network 

resource. Any change in ATC that is 

determined by the transmission 

provider to have resulted from the 

temporary termination shall be posted 

on OASIS during this temporary period. 

We agree that requiring network 

customers making temporary 

terminations to permanently forfeit 

rights to use this ATC would 

significantly reduce or eliminate firm 

third-party power sales. We emphasize, 

however, that a request to terminate a 

network resource that is not 

accompanied with a request to 

redesignate that resource at a specific 

point in time is to be considered an 

indefinite termination. After an 

indefinite termination of a resource, the 

network customer has no continuing 

rights to the use of such resource and 

future requests to designate that 

resource would be processed consistent 

with section 30.2 as a designation of 

new network resource. 

1550. We disagree with 

NorthWestern’s argument that, once 

upgrades specified through the 

interconnection process have been 

installed, the generator can be specified 

as a network resource by any customer, 

at the time of commercial operation of 

the generator or at any time in the 

future. The Commission has long noted 

that the generator interconnection 

process is separate and independent of 

the acquisition of transmission service 

for the same generator.895 The fact that 

system upgrades may be required to 

interconnect a generator does not mean 

any network customer is entitled to the 

use of that generator at all times, even 

in the event that the network customer 

indefinitely terminates the designation 

of that resource. The integration of 

network resources with different 

network customers presents different 

effects and flows on the transmission 

system that must be evaluated by the 

transmission provider. 

(3) Minimum Lead-Time 

Comments 

1551. EEI and Entergy argue that the 

Commission should not require 

transmission providers or network 

customers to undesignate a network 

resource for a specific amount of time 

prior to the commencement of an offsystem sale. In many instances, EEI 

argues, short-term firm power sales are 

made with relatively little lead time, 

particularly after events such as forced 

outages or unusual weather conditions. 

EEI and PNM–TNMP argue that 

requiring transmission providers or 

network customers to undesignate a 

specific amount of time prior to an offsystem sale would foreclose the 

possibility that firm sales could be made 

with short lead times. That, EEI argues, 

would adversely affect the sales market, 

without having any impact on ATC on 

the path used by the network resource 

because the network resource would not 

be undesignated. In EEI’s view, 

imposing lead times on undesignations 

of network resources would also result 

in treating network and native load 

customers less favorably than point-topoint customers. EEI points out that the 

pro forma OATT does not impose any 

minimum lead times on firm redirects of 

point-to-point transmission service 

pursuant to section 22 of the pro forma 

OATT or reassignment of transmission 

service pursuant to section 23 of the 

OATT, despite the fact that advance 

notice of redirects might make the 

resultant ATC more marketable. 

1552. Most commenters, however, 

appear to support the establishment of 

a minimum amount of time prior to 

operation that the transmission provider 

and other network customers should be 

required to terminate a network 

resource to ensure that the appropriate 

set of network resources are included in 

the ATC calculation, although they 

express widely varying opinions on 

what period of time would be 

appropriate. 

1553. Ameren and Pinnacle contend 

that the amount of time prior to 

operation that the transmission provider 

and other network customers should be 

required to terminate a network 

resource should be linked to the 

frequency of the calculation that gets 

standardized in the ATC process. 

Pinnacle contends that, if the 

undesignation and redesignation are 

performed on OASIS as they propose, 

ATC could be recalculated and posted 

immediately following the 

undesignation or redesignation. Ameren 

contends that it cannot comment further 

until the parameters of the ATC process 

are defined. FirstEnergy states that the 

amount of time should be consistent 

with the time periods required in 

markets, and that outside of markets, 

times should be established that 

coincide with such markets. Southern 

argues that the current practice, under 

which a resource is undesignated when 


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896E.g., EEI, NRECA Reply, PNM–TNMP, and 

Southern. 

it schedules point-to-point transmission 

service for an off-system sale, provides 

adequate time to ensure that the 

appropriate set of network resources is 

included in the ATC calculation. 

1554. PJM notes that, under its 

system, a generator resource with excess 

capacity can undesignate the excess 

resource on a ‘‘day ahead’’ basis. PJM 

believes that this is the proper amount 

of time needed to ensure resource 

adequacy. PJM argues that a generator 

should not, under any circumstance, 

change the designation of its resource 

‘‘same day.’’

1555. TranServ argues that, at a 

minimum, a request for undesignation 

should be supplied no later than the 

firm scheduling deadline so that 

released capacity may be acquired on a 

non-firm basis. If that data were 

required to be submitted earlier than the 

scheduled deadline, TranServ suggests 

the transmission provider may be able 

to offer incremental capacity for firm 

sales. TranServ requests that the 

Commission establish in the pro forma 

OATT some nominal timeframe for 

network customers to provide to the 

transmission provider their planned use 

of designated resources to serve loads. 

1556. Nevada Companies requests 

that, due to some system emergencies, 

force majeure events, and hourly 

scheduling of tie-line changes, they be 

allowed to change undesignation of 

network resources at any time to handle 

these types of events. 

Commission Determination 

1557. Commenters presented many 

alternative views in response to the 

Commission’s request in the NOPR for 

comments on the appropriate minimum 

lead-time prior to operation that the 

transmission provider and other 

network customers should be required 

to terminate a network resource to 

ensure that the appropriate set of 

network resources are included in the 

ATC calculation. In consideration of 

these comments, the Commission finds 

that the appropriate requirement is that 

network customers not be permitted to 

make firm third-party sales from any 

designated network resource without (1) 

undesignating that resource for the 

period of the third-party sale pursuant 

to pro forma OATT section 30.3 and (2) 

providing notice of such undesignation 

before the firm scheduling deadline (10 

a.m. the day before service commences). 

We find that this requirement strikes the 

appropriate balance, allowing 

undesignated capacity to be acquired on 

a non-firm basis but not creating an 

undue adverse effect on third-party 

sales. 

1558. We find it unnecessary to 

incorporate into the pro forma OATT 

provisions relaxed rules for changing 

the undesignation of network resources 

at any time to handle system 

emergencies, force majeure events, 

forced outages or unusual weather 

conditions, as suggested by some 

commenters. Other procedures such as 

those in NERC’s standard for Capacity & 

Energy Emergencies, EOP–002–2, or the 

possible use of capacity benefit margin, 

are more appropriate to deal with 

legitimate system emergencies. Outside 

the context of legitimate system 

emergencies, network customers should 

rely on appropriate planning and 

operation, rather than relaxed rules for 

designation of network resources. 

1559. We disagree with EEI’s 

argument that requiring a minimum 

lead-time will result in treating network 

and native load customers less favorably 

than point-to-point customers. In 

particular, EEI is incorrect in its 

statement that the OATT does not 

impose any minimum lead times on 

firm redirects of point-to-point 

transmission service or reassignments of 

transmission service. Firm point-topoint customers are also subject to 

deadlines for scheduling redirects 

pursuant to section 22.2 of the pro 

forma OATT. Furthermore, we find that 

EEI has provided no compelling 

evidence to support its argument that 

the adverse impacts on the market for 

firm energy with short lead times 

justifies having no minimum lead time. 

(4) General 

Comments 

1560. Several commenters argue that 

the Commission should not require 

network customers or the transmission 

provider to make formal modifications 

to their designations of network 

resources when they make firm sales to 

third parties from those resources.896

EEI and Southern argue that the practice 

of most network customers and 

transmission providers in the ten years 

since the Commission issued Order No. 

888 has been that a network resource is 

undesignated for any period for which 

the customer requests firm point-topoint transmission service from the 

generator or a third party. This practice, 

EEI argues, has not resulted in any 

adverse impacts on reliability or on the 

availability of transmission service and 

that, to the contrary, selling energy from 

network resources on a firm basis 

instead of a non-firm basis frees up firm 

transmission capacity that otherwise 

would have to be reserved for the 

network customer. EEI and NRECA 

contend that requiring formal 

undesignations is substantially more 

cumbersome for network customers and 

transmission providers making offsystem sales. 

1561. Progress Energy and TranServ 

argue that network customers should 

not have to go through the process of 

redesignating a network resource as new 

when the network customer once again 

needs to use this resource to serve 

network load. TranServ argues that such 

a transaction is exactly analogous to a 

redirect of firm point-to-point service on 

a firm basis and requests clarification of 

whether the provider should evaluate a 

request to undesignate a network 

resource concomitantly with the 

assessment of that same customer’s 

point-to-point request, as is done with 

redirects on a firm basis. 

1562. NRECA states that the 

undesignation requirement is too 

burdensome and, therefore, the 

Commission should adopt a 

comparability requirement that would 

allow network customers to utilize the 

practice that many public utility 

transmission providers use today: i.e., 

use designated resources for firm offsystem transactions or third party uses 

without having to go through the 

designation, undesignation and 

redesignation process. NRECA argues 

that existing scheduling procedures 

have allowed transmission providers to 

deliver power from their designated 

network resources for off-system 

merchant purposes reliably and should 

perform equally well for network 

customers, provided they still pay a 

point-to-point charge for the 

‘‘outbound’’ leg of a delivery to a 

neighboring network to serve the 

customer’s network load on the 

neighboring network. NRECA argues in 

its reply comments that, whatever the 

Commission decides to do, 

comparability is the most important 

principle when considering the 

undesignation policy and that 

‘‘grandfathering’’ agreements which 

would allow transmission providers to 

essentially get around this requirement 

would allow undue discrimination to 

continue. EEI disagrees in its reply 

comments with NRECA’s assertion that 

transmission providers currently have 

an advantage over network customers, 

arguing that the same standards apply to 

the transmission provider’s merchant 

function and network customers when 

they seek to make off-system sales from 

network resources. 

1563. PNM–TNMP contends that the 

Commission has held that formal 

undesignation and redesignation are not 

required, so long as the transmission 


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897See Virginia Electric and Power Co., 81 FERC 

¶ 61,125 at 61,111–12 (1997), reh’g denied, 82 FERC 

¶ 61,034 (1998). 898E.g., EEI, Pinnacle, and Progress Energy. 

899 In its reply comments, MDEA requests that 

any such flexibility afforded to transmission 

providers also be available to network customers on 

a non-discriminatory basis. 

provider treats its own resources and 

the network resources of network 

customers comparably. PNM–TNMP 

and Pinnacle further argue that to 

require formal undesignation and 

redesignation would appear to do 

nothing more than impose an extra layer 

of administration to the management of 

network resources, making power sales 

more difficult and potentially reducing 

financial benefits to end use customers. 

Bonneville argues that the 

Commission’s proposals regarding the 

use of network resources for surplus 

sales are likely to raise the cost to 

consumers. 

1564. Duke requests that the 

Commission clarify that any product 

that is not ‘‘designatable’’ as a network 

resource by a buyer may be sold by a 

seller that happens to be a network 

customer, without having to 

undesignate any network resources. 

1565. Suez Energy NA requests that 

the Commission ensure that a utility 

cannot use redesignation to hoard 

transmission capacity in order to 

deprive independent power producers 

of access to the grid. It contends that a 

utility could consistently hold 

transmission to serve generation that 

never runs for economic reasons and, 

the day before power flows, redesignate 

that transmission to accommodate a 

third-party purchase, effectively using 

its ability to redesignate network 

transmission capacity to hoard scarce 

ATC. In order to prevent potential 

abuse, Suez Energy NA agrees with the 

NOPR proposal to require transmission 

providers to use the same OASIS 

procedures to designate and terminate 

network status for themselves that they 

apply to network customers. 

1566. If the Commission requires 

formal designations and undesignations, 

EEI asks the Commission to clarify 

whether it is changing its policy that it 

is not necessary to modify service 

agreements in such circumstances in 

order to avoid requiring transmission 

providers to make numerous filings 

amending service agreements.897 If 

formal undesignations are required, EEI 

argues on reply that each transmission 

provider would be required to submit a 

revised application for network service 

under section 29.2 of the pro forma 

OATT both at the time the resource was 

undesignated and at the time that 

resource was redesignated. EEI also 

argues that formal undesignation would 

require the execution and filing of 

revised network service agreements 

reflecting the changes. 

1567. South Carolina E&G argues in 

its reply comments that off-system sales 

of firm power are typically in the form 

of a slice-of-system sale. South Carolina 

E&G requests that the Commission 

provide guidance for how to treat such 

a sale of power, suggesting that the 

transmission provider be permitted to 

undesignate a slice of a system 

sufficient to support the firm power sale 

and then, at the conclusion of the sale, 

redesignate that slice of the system as a 

network resource. 

1568. While generally supporting the 

Commission’s proposal to continue to 

allow network customers and the 

transmission provider, with respect to 

its native load, to undesignate network 

resources to allow them to make sales to 

third parties, some commenters seek 

certain changes, consideration, or 

clarification by the Commission.898 EEI, 

joined by TDU Systems on reply, argue 

that the Commission should modify its 

statement that network customers 

should be permitted to undesignate 

network resources ‘‘on a short-term 

basis to make off system sales.’’ They 

argue that nothing in Order No. 888, the 

Commission’s decisions, or the public 

interest requires that network resources 

be undesignated only for short-term 

sales. They further argue that such sales 

need not be ‘‘off-system.’’ Progress 

Energy argues that the Commission 

should only allow transmission 

customers to undesignate network 

resources to make firm off-system sales 

for a term which the transmission 

customer has adequate generation 

reserves to serve its network load. In its 

view, the transmission provider also 

must have the authority to deny the 

designation or undesignation of the 

network resources if the transmission 

provider determines that it needs the 

network resources to preserve the 

reliability of its transmission system or 

to ensure that there is sufficient 

transmission capability to support the 

requested changes. NRECA disagrees on 

reply, arguing that granting transmission 

providers the authority to deny 

undesignation requests would give them 

too much discretion and the perfect 

opportunity to discriminate. 

1569. Progress Energy agrees with the 

Commission that network service 

involves the entire transmission 

provider’s system and does not involve 

a contract path like point-to-point 

service. It also agrees that the delivery 

of a network resource once inside the 

system does not need to be redirected. 

Progress Energy notes that peaking 

resources have low capacity factors and, 

therefore, their transmission 

reservations are frequently 

underutilized. They request that 

network customers be given the ability 

to optimize their transmission 

purchases by bringing energy into the 

host transmission provider’s system 

from other designated network 

resources in times when they are not 

using their peaking designated 

resources. 

1570. MDEA, Progress Energy, and 

Entergy request that, for reliability and 

economic reasons, network customers 

be given the flexibility to substitute new 

designated network resources without 

abandoning the original transmission 

queue position of an existing designated 

network resource.899 If the Commission 

does not change its proposal in order to 

provide network customers with this 

flexibility, Progress Energy contends 

that point-to-point service will be a 

superior service to network service. 

1571. Entergy states that it is 

important for the Commission to 

recognize that the undesignation of 

network resources can be used by 

network customers as a means of 

allowing merchant generators the 

opportunity to displace existing 

resources in serving network and native 

load. It argues that the Commission 

should be wary of limiting the ability of 

a network customer to undesignate 

network resources, as any such 

restriction will have broader 

implications than just the ability of 

network customers, including the 

transmission provider’s wholesale 

merchant function, to sell that resource 

off-system with point-to-point service. 

1572. Entergy also requests that the 

Commission clarify that, while network 

customers cannot redirect network 

service, nothing in this prohibition 

prevents transmission providers from 

studying requests to designate new 

network resources as displacements of 

existing network resources. It argues 

that preventing network customers from 

using automated study functions would 

significantly hinder the ability of these 

customers to substitute their existing 

long-term resources with short-term 

purchases of energy and capacity from 

merchant generators when it is 

economical to do so. 

1573. TDU Systems argue that 

network customers (and transmission 

providers to the extent they serve native 

load on other systems) should be able to 

schedule output on a firm basis from 


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900 93 FERC ¶ 61,331 at 62,128 (2000). 

network resources on one system to 

serve their network loads on 

neighboring systems without having to 

designate and redesignate network 

resources among the various 

transmission providers’ control areas. 

TDU Systems state this would permit 

LSEs that serve across multiple systems 

to come closer to replicating the 

economic dispatch of control area 

operators, significantly reducing the 

cost of discharging their service 

obligations to the customers they serve. 

1574. Xcel opposes requiring a 

transmission customer to undesignate a 

network resource even in a situation 

where the resource is used only 

transiently to provide off-system sales, 

arguing that such policy would have 

significant adverse consequences for 

customers across the country. It points 

out that it is native load customers that 

frequently benefit from purchase of 

economy energy and that, if an 

undesignation was required to deliver 

economy energy, most such transactions 

likely would not occur. Xcel also argues 

the NOPR concepts relating to 

designation of network resources and 

justification of economy energy 

purchases are irrelevant in the context 

of an RTO where energy is procured and 

dispatched throughout the RTO on a 

security constrained economic basis. 

1575. EEI, joined by TDU Systems on 

reply, requests that the Commission 

clarify that any changes to the 

procedures for designating and 

undesignating network resources apply 

only to designations made after the 

Final Rule becomes effective, in order to 

avoid substantial adverse impacts on the 

reliability of service to network and 

native loads. Duke and Pinnacle request 

that the Commission require NAESB to 

develop standards that address 

undesignation and redesignation and 

allow sufficient time for the NAESB 

process and for OASIS tools to be 

developed and approved, prior to the 

implementation of a new policy. 

TranServ asks that the undesignation of 

network resources be supported on 

OASIS. 

Commission Determination 

1576. We disagree with commenters 

arguing that formal undesignations and/ 

or redesignations of resources used to 

make firm third-party sales should not 

be required. The undesignation and 

redesignation requirements exists not 

only to promote reliability, but also to 

prevent undue discrimination, promote 

comparable treatment of customers, and 

increase the accuracy of ATC 

calculations. We find that the interest in 

advancing these policy goals overrides 

the minimal burden and cost that 

submitting undesignations and/or 

redesignations entails. We disagree with 

Xcel’s argument that most economy 

energy purchases that benefit its native 

load customers likely will not take place 

if undesignation of network resources is 

required prior to firm, third-party sales. 

First, the requirement to undesignate 

network resources only applies to firm 

sales, while typical non-firm economy 

energy transactions would not require 

undesignation. Second, undesignating a 

network resource is not unduly 

burdensome, consisting only of 

electronically submitting several items 

of information, as described above. 

Therefore, we do not believe that a 

transaction prevented purely as a result 

of the requirement to undesignate 

network resources would have provided 

any significant economic value had it 

taken place. 

1577. We find that requests to allow 

‘‘informal undesignations’’ appear to be 

simply requests to not require 

undesignations at all. Since the salient 

feature of requiring an undesignation is 

that the proper account is taken of the 

effects on ATC, informal 

undesignations, which do not take 

proper account of the fact that a 

resource is no longer a designated 

network resource, appear to serve no 

purpose. 

1578. With regard to PNM-TNMP’s 

argument that the Commission has held 

that formal undesignation and 

redesignation are not required, so long 

as the transmission provider treats its 

own resources and the network 

customer’s resources comparably, we 

believe PNM-TNMP misunderstands our 

policies. We note that PNM-TNMP 

provides no citation to Commission 

precedent to support its statement. 

1579. Duke requests clarification as to 

whether a network customer must 

undesignate a network resource in order 

to make a third-party sale from that 

resource if the third-party sale would 

not itself qualify to be designated as a 

network resource. We reiterate the 

existing requirement that designated 

network resources must not be 

committed for sale to non-designated 

third-party load or include resources 

that otherwise cannot be called upon to 

meet the network customer’s network 

load on a noninterruptible basis. We 

find that a resource is ‘‘committed for 

sale to a non-designated third party 

load’’ if a power purchase agreement for 

the sale from that resource provides for 

penalties if service to the third party is 

interrupted in order to serve the 

designated network load. 

1580. In response to comments by 

EEI, NRECA, and Suez Energy NA, we 

reiterate that all parties, including 

transmission providers serving their 

native loads, are subject to these 

requirements for designation and 

undesignation of network resources. 

Section 28.2 of the pro forma OATT 

clearly provides that transmission 

providers are required to designate 

resources and loads in the same manner 

as any network customer. We encourage 

parties suspecting that transmission 

providers or other network customers 

are not conforming to the requirements 

for designating or undesignating 

network resources to report their 

concerns using the Commission’s 

Enforcement Hotline. 

1581. EEI has requested clarification 

of whether the Commission is changing 

its policy that transmission providers do 

not need to modify network service 

agreements when network resources are 

undesignated and redesignated. We 

have not proposed and do not intend to 

begin requiring that network customers 

file modified service agreements when 

network resources are designated or 

undesignated. As we explained in 

Dayton Power and Light Co.,900

‘‘changes in network resources may 

require the customer to file a request 

under OASIS, but a change to the 

information recorded initially in the 

network service agreement is not a 

requirement.’’ EEI also argues that, if 

formal undesignations are required, 

then each transmission provider would 

be required to submit a revised 

application for network service under 

section 29.2 of the pro forma OATT, 

both at the time the resource was 

undesignated and the time that resource 

was redesignated. We disagree. There is 

no requirement that a transmission 

provider submit a revised application 

for network service every time a 

resource is designated or undesignated. 

1582. In response to a request by 

South Carolina E&G, we clarify that firm 

third-party sales may be made from an 

undesignated portion of a network 

customer’s network resources (i.e., a 

‘‘slice-of-system sale’’), so long as all of 

the applicable requirements are met. In 

particular, the network customer must 

submit undesignations for each portion 

of each resource supporting the thirdparty sale. If the undesignation is 

temporary, then the request must be 

accompanied by a request to redesignate 

the resource(s) on a specific date. When 

the undesignation takes effect, the 

network customer must update the 

capacities specified in its list of 

designated network resources posted on 

OASIS. 

1583. We agree with EEI and TDU 

Systems’ comments that there should be 


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901 18 CFR 37.6(e)(2). 

902Order No. 888 at 31,751. 

903 Idaho Power Co., 103 FERC ¶ 61,182 at P 2 

(2003) (Idaho Power). 

904 Id. at P 4. 

no minimum term for undesignations. 

We also agree with EEI and TDU 

Systems’ arguments that network 

customers should not be restricted to 

temporarily undesignating network 

resources only for use in off-system 

sales, and clarify that network 

customers are not so restricted. 

1584. We agree with Progress Energy 

that network customers should only 

make firm third-party sales when they 

have sufficient generation reserves to 

serve their loads. However, the purpose 

of the pro forma OATT is to provide 

nondiscriminatory transmission access, 

not to enforce generation adequacy 

requirements. 

1585. With regard to Progress Energy’s 

request for flexibility to evaluate 

potential impacts to the transmission 

system related to the undesignation and 

redesignation of network resources, we 

find that situations where 

undesignations cannot be 

accommodated due to transmission 

constraints should be extremely rare, 

such as highly-extraordinary 

counterflow situations. In such rare 

situations, the transmission provider 

should attempt to remedy the situation 

without denying the undesignation. If it 

is determined that the resource cannot 

be undesignated without jeopardizing 

reliability, then the transmission 

provider may deny the request for 

undesignation. 

1586. We share NRECA’s concern that 

allowing transmission providers to deny 

undesignations for reliability reasons 

could give a direct market competitor a 

significant opportunity to discriminate, 

but must weigh this concern against our 

significant interest in preserving 

reliability. We point out that 

transmission providers denying requests 

for service or changes to service because 

of reliability concerns must post a 

description of such denials in 

accordance with section 37.6(e)(2) of the 

Commission’s regulations.901 Again, we 

encourage any parties with concerns 

about denials of service or changes to 

service by a transmission provider for 

reasons of reliability to report their 

concerns to the Commission’s 

Enforcement Hotline. 

1587. We deny requests by MDEA, 

Progress Energy, and Entergy that 

network customers be given the 

flexibility to substitute new designated 

network resources without abandoning 

the original transmission queue position 

of an existing designated network 

resource. These parties seem to be 

requesting that a network customer be 

allowed to be ‘‘first in line’’ to use the 

ATC freed up by an undesignation of a 

network resource, as long as the 

network customer uses that ATC to 

designate an alternate resource. We 

disagree. Granting this request would, 

without any apparent justification, put 

point-to-point customers seeking ATC 

freed up by an undesignation at a 

disadvantage. We also disagree that, if 

the Commission does not allow network 

customers this flexibility, point-to-point 

service will be a superior service to 

network service. Progress Energy seems 

to be arguing that the point-to-point 

customer’s ability to engage in a redirect 

affords that customer more flexibility 

than the network customer. We point 

out that redirects of point-to-point 

service on a firm basis are only on an 

‘‘as-available’’ basis. Firm point-to-point 

customers cannot redirect unless ATC is 

available to support such a redirect after 

all higher-priority requests have been 

accommodated. 

1588. Entergy has requested 

clarification that, while network 

customers cannot redirect network 

service, nothing in this prohibition 

prevents transmission providers from 

studying requests to designate new 

network resources as displacements of 

existing network resources. Although 

Entergy’s request is unclear, we reiterate 

that redirects are not allowed within the 

context of network service and that 

network customers are not ‘‘first in line’’

to use ATC freed up by their 

undesignation of another network 

resource. Such requests must be 

processed taking proper account of all 

competing transmission service requests 

of higher priority. 

1589. We disagree with TDU System’s 

argument that network customers 

should be able to schedule output on a 

firm basis from network resources on 

one system to serve their network loads 

on neighboring systems without having 

to designate and redesignate network 

resources among the various 

transmission providers’ control areas. 

Allowing network customers to not 

formally undesignate and redesignate 

network resources, even only when 

using those resources to serve their 

network loads on neighboring systems, 

will necessarily result in inaccurate 

evaluations of ATC. We reiterate that 

the burden associated with 

undesignating and redesignating the 

resources is particularly light and find 

that requiring network customers to 

make temporary undesignations when 

making third-party firm sales is thus 

justified in light of the ATC-related 

benefits. 

1590. Xcel argues that the concepts 

relating to designation of network 

resources are irrelevant in the context of 

an RTO where energy is procured and 

dispatched throughout the RTO on a 

security constrained economic basis. We 

agree that Day 2 RTOs do not use the 

physical rights model contemplated 

under the pro forma OATT and, hence, 

not all the provisions discussed here are 

directly applicable to Day 2 markets. 

However, as we explain in section 

IV.C.2, RTOs and ISOs must make the 

necessary filings to comply with the 

Final Rule, or demonstrate that their 

existing tariff provisions are consistent 

with or superior to the terms of the 

revised pro forma OATT. 

1591. We agree with parties arguing 

that network customers should not be 

required to use the new NAESB 

processes and OASIS tools to be 

developed in response to this section 

until such time as the NAESB standards 

and OASIS functionality have been 

developed and implemented. However, 

once the new standards and 

functionality are in place, network 

customers must use these new 

procedures to undesignate (whether 

temporarily or as part of an indefinite 

termination) any network resources, 

regardless of the date that those 

resources were originally designated. 

7. Clarifications Related to Network 

Service 

a. Secondary Network Service 

1592. Section 28.4 of the existing pro 

forma OATT allows a network customer 

to deliver energy to its network load 

from non-designated network resources 

on an as-available basis without 

additional charge, referred to as 

secondary network service. In Order No. 

888, the Commission described such 

energy as non-firm economy energy 

purchases used to displace firm network 

resources.902

1593. The use of secondary network 

service to deliver purchased power 

when a network customer is making offsystem sales has been raised in several 

Commission investigations and audits. 

In Idaho Power, the Commission 

accepted a settlement with Idaho Power 

related to Idaho Power’s incorrect use of 

the native load priority to access its 

transmission system.903 In Idaho Power, 

the utility’s wholesale merchant 

function purchased power outside of 

Idaho Power’s control area to facilitate 

an off-system sale and used secondary 

network service to bring the purchases 

into Idaho Power’s control area.904 In 

accepting the settlement, the 

Commission stated that ‘‘[i]t is 

axiomatic that the native load priority 


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905 Id. 

906 MidAmerican Energy Co., 112 FERC ¶ 61,346 

at P 6 (2005). 

907E.g., Alberta Intervenors, Southern, Suez 

Energy NA, and TAPS. 

908E.g., EEI, Entergy, Northwest Parties, NRECA, 

Pinnacle, PGP, Southern, and Xcel. 

909 MidAmerican Energy Co., 112 FERC ¶ 61,346 

at P 6 (2005) (MidAmerican). Following an audit, 

the Commission found that MidAmerican’s 

cannot be used to complete sales that 

are not necessary to serve native 

load.’’ 905 In MidAmerican, the 

Commission issued an audit report that 

contained a finding that MidAmerican’s 

wholesale merchant function used 

network service instead of point-topoint service to deliver short-term 

energy purchases to its control area that 

were not used to serve MidAmerican’s 

native load.906

NOPR Proposal 

1594. In the NOPR, the Commission 

proposed to clarify that a network 

customer may not use secondary 

network service to import energy onto 

its system to support an off-system sale 

if the purchased power does not 

displace the customer’s own higher cost 

generation. The Commission therefore 

proposed to modify section 28.4 of the 

pro forma OATT to state that a network 

customer may use secondary network 

service only to deliver economy energy 

and to define ‘‘economy energy’’ as 

energy purchased by a network 

customer that displaces the customer’s 

own higher cost generation for the 

purpose of serving the customer’s 

designated network loads. The 

Commission further explained that all 

participants engaging in purchases for 

resale must compete on a comparable 

basis and use point-to-point service to 

complete all segments of a purchase for 

resale off-system. 

(1) Overview 

Comments 

1595. Several commenters agree with 

the Commission and support the 

proposed clarification regarding the use 

of secondary network service.907 Alberta 

Intervenors state that such a restriction 

ensures fair competition among network 

customers and preserves the entitlement 

of native load customers. 

1596. Other participants oppose the 

proposal, arguing that it is too broad and 

would interfere with legitimate activity 

by network customers.908 EEI points out 

that, if a network customer is using all 

available network resources but is still 

purchasing energy from non-designated 

network resources to meet its peak 

native load, the network customer 

would need to rely on secondary service 

to transmit this purchase. In EEI’s view, 

the Commission’s proposal would 

prevent this customer from using 

secondary service for this non-economy 

energy, thereby interfering with its 

service obligations. To avoid such cases, 

EEI, Pinnacle, and PGP recommend that 

secondary service not be limited to 

economy energy only. NRECA states 

that the Commission’s proposed 

limitation on the use of secondary 

service would prevent network 

customers from meeting their native 

load obligations in cases of extreme 

weather and power outages. NRECA 

asks the Commission to state explicitly 

in section 28.4 of the pro forma OATT 

that secondary service may not be used 

to facilitate off-system third party sales, 

but rather must be used to import power 

needed to serve network load 

economically and efficiently. Entergy 

suggests the Commission abandon the 

limitation and specify simply that 

secondary service cannot be used to 

serve loads other than the network or 

native load. 

1597. Others argue that the restriction 

of secondary service to only economy 

energy would have unintended 

consequences regarding the purchase of 

renewable resources. Emerald, Flathead, 

and the Northwest Parties state that, for 

reasons of customer demand or 

contractual obligation, network 

customers may be required to purchase 

renewable power that generally is more 

expensive than traditional thermal or 

hydro electric generation. These 

purchases could displace less expensive 

non-renewable resources, resulting in 

the need for the network customer to 

make off-system sales of the nonrenewable resources. Emerald, Flathead, 

and Northwest Parties suggest that the 

Commission revise the definition of 

‘‘economy energy’’ to include an 

exception for renewable energy. TAPS 

raises a similar issue, asking the 

Commission to clarify that economy 

purchases as well as substitute 

resources qualify for use of secondary 

service. 

1598. EEI argues that the proposed 

limitation on secondary service would 

require all network customers to engage 

in a specific form of Commissionregulated economic dispatch, while 

requiring transmission providers to 

evaluate each resource and become 

‘‘dispatch police.’’ Entergy, SPP, and 

PGP agree. They assert that calculating 

the ‘‘cost’’ of power is problematic, 

inherently subjective and burdensome 

because transmission providers lack the 

necessary knowledge to perform this 

analysis. EEI, Entergy, SPP, and PGP 

instead suggest that the Commission 

conduct periodic audits of secondary 

service to ensure compliance with the 

requirements of OATT section 28.4 

rather than transmission providers. 

1599. Although Powerex supports the 

Commission’s restriction on the proper 

use of secondary service, it also states 

that determining whether or not an 

import would qualify as ‘‘economy 

energy’’ would be difficult. Powerex 

requests that the Commission 

implement specific rules in advance of 

such transactions to resolve uncertainty. 

It suggests a capacity test to prevent 

preferential acquisition of generation 

capacity, a tariff prohibition on the use 

by the network customer or its energy 

affiliates of any export transmission 

capacity made available on another 

intertie, and the modification of 

business practices governing 

curtailment. In reply, Alberta 

Intervenors agree with Powerex’s 

proposed changes to curtailment 

practices, but disagree with the other 

two elements. Alberta Intervenors assert 

that the tariff prohibition causes 

inefficient use of ATC and that the 

capacity test is not a stand-alone test 

and, as a result, would only be helpful 

as a supplement to the ‘‘economy 

energy’’ test. 

1600. Some participants raise other 

issues not addressed in the NOPR. 

South Carolina E&G asks that the 

Commission clarify its policy on 

purchases of economy energy, as well as 

provide a clear definition of the 

acceptable trading practices—notably 

parking, hubbing, and lending—under 

the current pro forma OATT. Emerald 

and Flathead request the Commission to 

revise the definition of ‘‘network load’’

in section 1.24 of the pro forma OATT 

to allow point-to-point and network 

service to the same discrete point of 

delivery. Morgan Stanley asks that the 

Commission explain why using 

secondary service to make an off-system 

purchase while there is any off-system 

sale during the same interval is 

improper and whether the Commission 

will prohibit such activity only if the 

off-system purchase and sale are part of 

a single transaction. Finally, Xcel argues 

that the concepts relating to designation 

of network resources are irrelevant in 

the context of an RTO where energy is 

procured and dispatched throughout the 

RTO on a security constrained economic 

basis. 

Commission Determination 

1601. In general, the Commission 

agrees with parties that favor an 

expansion of the proper use of 

secondary network service. Although 

we affirm our finding in 

MidAmerican,909 the Commission 


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wholesale merchant function used network service 

instead of point-to-point service to deliver shortterm energy purchases to its control area that were 

not used to serve MidAmerican’s native load. The 

Commission stressed that the use of secondary 

network service is not for the purpose of serving offsystem sales. Id. at P 6. The modifications to section 

28.4 adopted in this Final Rule do not alter that 

limitation. 

recognizes that there are instances 

outside the proposed definition of 

economy energy that warrant the use of 

secondary service in order to serve 

network loads reliably. The Commission 

therefore declines to adopt the 

definition of economy energy proposed 

in the NOPR and, instead, will retain 

the existing section 28.4 that permits 

use of secondary network service ‘‘to 

deliver energy to its Network Loads.’’

1602. With respect to Powerex’s 

comments, we reject the requested 

clarifications as Powerex has not fully 

supported the use of its proposed 

capacity test or other measures and has 

not demonstrated that such test would 

not preclude legitimate uses of this 

priority as noted in the NOPR. If parties 

suspect inappropriate use of secondary 

network service, they may report the 

suspected activity to the Commission’s 

Enforcement Hotline or file a compliant 

with the Commission pursuant to FPA 

section 206. Furthermore, the 

Commission’s staff will continue to 

provide oversight of all tariff-related 

activities through its enforcement 

program. 

(2) ‘‘On an as-available basis’’

1603. Section 28.4 of the existing pro 

forma OATT allows a network customer 

to use secondary network service to 

deliver energy purchases to its network 

load from non-designated resources ‘‘on 

an as-available basis.’’ However, the 

current pro forma OATT does not 

specify how a network customer must 

arrange for secondary network service. 

NOPR Proposal 

1604. In the NOPR, the Commission 

proposed to modify section 28.4 of the 

pro forma OATT to clarify that a 

network customer does not need to file 

an application for network service to 

receive secondary service. Instead, the 

customer must merely request such 

service on OASIS in a manner 

consistent with pro forma OATT 

sections 18.1 and 18.2 (Procedures for 

Arranging Non-Firm Point-to-Point 

Transmission Service). 

Comments 

1605. TDU Systems requests that the 

Commission clarify that time constraints 

located in OATT section 18.3 are not 

applicable to secondary service. Section 

18.3 provides that requests for non-firm 

point-to-point service shall not be made 

before certain specified periods (more 

than 60 days in advance for monthly 

service, more than 14 days in advance 

for weekly service, etc.). TDU Systems 

states that some of its members 

currently use secondary service to 

access economy off-system purchases 

where intervening transmission 

constraints preclude the designation of 

those resources as network resources for 

long periods of time. Application of the 

non-firm point-to-point service request 

deadlines would impair TDU Systems’

ability to rely on secondary service in 

those instances since they would extend 

beyond the timing requirements set 

forth in section 18.3. 

Commission Determination 

1606. The Commission clarifies that 

secondary service must be requested in 

accordance with section 18, including 

the timing restrictions set forth in 

section 18.3, of the pro forma OATT. 

Secondary service is on an as-available 

basis, and network customers should 

not be permitted to lock in such service 

in advance of other non-firm uses of 

available transmission. Allowing lowerpriority secondary service to have a 

scheduling advantage over non-firm 

transmission would be inappropriate 

and would discourage the use of nonfirm transmission service, thereby 

minimizing the revenue credits from 

non-firm transmission service that 

benefit all firm transmission customers. 

(3) Redirect of Network Service 

1607. The current pro forma OATT 

does not include any provision to 

change the point of receipt for an offsystem designated network resource in 

a manner similar to redirect of point-topoint service. We are aware, however, 

that several transmission providers have 

posted business practices that allow 

network customers either to substitute 

an off-system non-designated network 

resource for a designated network 

resource or to redirect the point of 

receipt associated with an existing 

network resource. 

NOPR Proposal 

1608. The Commission proposed to 

clarify that network customers may not 

redirect network service in a manner 

comparable to redirect of point-to-point 

service, as network service involves no 

identified contract path and is, 

therefore, not a directable service. 

Should a network customer wish to 

substitute one designated network 

resource for another, the Commission 

stated that it must terminate the existing 

resource and designate a new one. The 

Commission explained that the network 

customer could also request to 

redesignate its original network resource 

by making a request to designate a new 

network resource. Alternatively, a 

network customer could use secondary 

network service when it wants to 

substitute a non-designated network 

resource for a designated network 

resource on an as-available basis. 

Comments 

1609. MISO strongly supports the 

Commission’s clarification stating that 

network service is not a directable 

service and believes that the proposal 

appropriately clarifies the Commission’s 

policy on redirect service. TDU Systems 

and NRECA, however, believe that the 

Commission should allow redirects of 

network service to deliver an LSE’s 

resources. TDU Systems assert that 

redirect of network service is critical to 

LSEs serving native load across multiple 

transmission systems because it allows 

the amount of flexibility necessary to 

manage power supply costs. In addition, 

in TDU Systems’ view, redirects have no 

effect on system reliability. 

1610. EEI argues on reply that it is 

unclear why redirects of network 

service should be allowed. The 

advantage of redirecting firm point-topoint service is that the customer does 

not have to pay an additional charge for 

transmission service. However, both 

TDU Systems and NRECA agree that 

network customers should pay an 

additional charge for transmission 

service from network resources to offsystem loads. 

1611. Sacramento alternatively 

recommends that the Commission 

remove the ban on off-system sales in 

order to maximize efficiency in 

allocating transmission capacity. 

Occidental requests that the 

Commission place all transmission, 

including on behalf of native load, 

under the OATT guidelines to ensure 

that service is provided in a nondiscriminatory fashion. 

Commission Determination 

1612. The Commission clarifies that 

network customers may not redirect 

network service in a manner comparable 

to the way customers redirect point-topoint service. Point-to-point service 

consists of a contract-path with a 

designated point of receipt and point of 

delivery. Network service has no 

identified contract-path and is therefore 

not a directable service. Network service 

instead provides for the integration of 

new network resources and permits 

designation of another network 

resource, which has the same practical 

effect as redirecting network service. If 

the customer wants to permanently 


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910Order No. 888–A at 30,216. 

911Order No. 888 at 31,736. 

912Order No. 888–A at 30,258–61. 

913E.g., TAPS, TDU Systems, AMP-Ohio, and 

CAC/EPUC. 

914TDU Systems and TAPS also cite Consumers 

Energy, 98 FERC ¶ 61,333 at 62,410 (2002) 

(requiring that a transmission provider’s retail load 

associated with behind the meter generation be 

included in the transmission provider’s load ratio 

share to ensure comparability between transmission 

providers and network customers in the calculation 

of load ratio share). 

915E.g., AMP-Ohio, CAC/EPUC, and TAPS. 

916Citing Occidental Chemical Corporation v. 

PJM Interconnection, L.L.C., and Delmarva Power & 

Light Company, 102 FERC ¶ 61,275 at P 14 (2003) 

(‘‘Access charges for use of PJM’s transmission 

system should be allocated to network customers 

based on a network customer’s actual use of PJM’s 

system, consistent with the principle of costcausation.’’); PJM Interconnection, L.L.C., 107 FERC 

¶ 61,113, at P 28 (2004). 

917E.g., AMP-Ohio, TAPS, and TDU Systems 

(citing PJM Interconnection, L.L.C., 107 FERC 

¶ 61,113 (2004), reh’g denied, 108 FERC ¶ 61,032 

(2004) (PJM)). 

918This settlement agreement was accepted in 

PJM Interconnection, L.L.C., 113 FERC ¶ 61,279 

(2005). 

919PJM Interconnection, L.L.C., 113 FERC 

¶ 63,024 (2005). 

substitute one designated network 

resource for another, it should terminate 

the designation of the existing network 

resource and designate a new network 

resource. The customer could then 

simply request to redesignate its original 

network resource, if it so desires, by 

making a request to designate a new 

network resource. The ability of a 

network customer to also temporarily 

substitute one designated network 

resource for another is addressed in 

section V.D.6. 

1613. The Commission rejects 

Sacramento’s proposal to remove the 

ban on off-system sales. Network service 

is not based upon making off-system 

sales, but rather on integrating a 

network customer’s resources with its 

load. Transmission providers must take 

point-to-point transmission service for 

off-system sales and network customers 

should be treated comparably. The 

Commission also rejects Occidental’s 

request to place all transmission, 

including on behalf of native load, 

under the pro forma OATT. In Order 

No. 888–A the Commission clarified 

that a ‘‘transmission provider is not 

required to ‘take service’ under its own 

tariff for the transmission of power that 

is purchased on behalf of bundled retail 

customers.’’ 910 However, the 

Commission required that transmission 

providers, pursuant to section 28.2 of 

the pro forma OATT, must designate 

network resources and network loads in 

the same manner as any network 

customer. Occidental offers no 

explanation why the existing 

requirement of section 28.2 is not 

sufficient to address its concerns. 

b. Behind the Meter Generation 

1614. In Order No. 888, in response to 

customers with load served by ‘‘behind 

the meter’’ generation that sought to 

eliminate such load from their network 

calculation, the Commission found that 

a customer may exclude a particular 

load at discrete points of delivery from 

its load ratio share of the allocated cost 

of the transmission provider’s integrated 

system. The Commission determined, 

however, that customers electing to do 

so must seek alternative transmission 

service, such as point-to-point 

transmission service, for any load that 

has not been designated as network load 

for network service.911 In Order No. 

888–A, the Commission stated that it 

would permit a network customer to 

either designate all of a discrete load as 

network load under the network 

integration transmission service or to 

exclude the entirety of a discrete load 

from network service and serve such 

load with the customer’s behind the 

meter generation and/or through any 

point-to-point transmission service.912

1615. The Commission did not 

address the subject of behind the meter 

generation in the NOPR. A few 

commenters nonetheless proposed 

revisions to the pro forma OATT to 

require netting of a network customer’s 

behind the meter generation against 

their network load as described in more 

detail below. 

Comments 

1616. Some commenters argue that, in 

order to meet the objective of 

eliminating discrimination in the 

provision of open access transmission 

service, the Commission must require 

comparable treatment between retail 

native load and network customers by 

allowing network customers to net 

behind the meter generation against 

their network load.913 Specifically, such 

commenters argue that the Commission 

should modify the current pricing rules 

for network service to allow an LSE’s 

load ratio share to reflect the reduction 

in load caused by behind the meter 

generation serving retail load.914 In 

support of this position, these 

commenters argue that assigning 

transmission-related costs to customers 

that do not rely on the transmission 

provider’s system to serve load is 

inconsistent with the Commission’s 

cost-causation principles.915 For 

example, CAC/EPUC contends that 

customer generation does not cause the 

transmission provider to incur costs 

when power is not being sold to or 

taken off the grid. Similarly, AMP-Ohio 

argues that it is inappropriate to assign 

a full load ratio share of transmissionrelated costs to behind the meter 

generation customers that do not use the 

network to the full extent of their load 

ratio shares.916 Further, CAC/EPUC 

asserts that measuring the customer’s 

use of the transmission system at the 

customer’s meter would be appropriate 

as it would demonstrate that, if no 

power flows to the customer from the 

grid occur, that customer has not used 

nor caused costs to be incurred by the 

grid for the delivery of its energy 

requirements. 

1617. Some commenters note that the 

Commission has approved PJM netting 

provisions that apply to behind the 

meter generation used by non-retail and 

wholesale customers to serve load.917

These same commenters further observe 

that PJM has filed with the Commission 

to expand participation in its behind the 

meter generation netting program to 

include municipal, electric 

cooperatives, and electric distribution 

transmission customers who take 

network service on the PJM system 

pursuant to a settlement agreement filed 

by PJM on October 24, 2005 in Docket 

No. EL05–127–000.918

1618. Further, both TAPS and AMPOhio argue that behind the meter 

generation provides benefits to the 

transmission provider that should be 

taken into account as part of system 

planning obligations. For instance, 

AMP-Ohio asserts that utility planning 

can and should be able to take into 

account the ability of customers to 

reduce their load on the system with 

behind the meter generation. TDU 

Systems also notes PJM’s representation 

that allowing municipal and electric 

cooperative system participation in 

behind the meter generation netting 

programs increased reliability and 

demand response opportunities on 

PJM’s system.919 Similarly, TAPS 

observes that PJM’s rules reserve the 

right to call upon non-retail behind the 

meter generation under certain 

conditions. 

Commission Determination 

1619. The Commission is not 

persuaded to require transmission 

providers to allow netting of behind the 

meter generation against transmission 

service charges to the extent customers 

do not rely on the transmission system 

to meet their energy needs. Commenters 

in this proceeding have not provided 

any different arguments that were not 

fully considered and addressed in Order 

No. 888, et al. The existing pro forma 

OATT already permits transmission 


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920We note that EEI responds to allegations of 

undue discrimination in the calculation of load 

ratio share costs in the OATT Definitions section of 

this Final Rule. 921Order No. 888–A at 30,260–61. 922PNM–TNMP and TranServ. 

customers to exclude the entirety of a 

discrete load from network service and 

serve such load with the customer’s 

behind the meter generation and 

through any needed point-to-point 

transmission service, thereby reducing 

the network customer’s load ratio share. 

Therefore, the Commission’s existing 

policy already provides customers with 

the opportunity to reduce network 

service costs to the extent a customer is 

not relying on the transmission system 

to meet its energy needs.920 As the 

Commission concluded in Order No. 

888–A, transmission customers 

ultimately must evaluate the financial 

advantages and risks and choose to use 

either network integration or firm pointto-point transmission service to serve 

load.921 We believe it is most 

appropriate to continue to review 

alternative transmission provider 

proposals for behind the meter 

generation treatment on a case-by-case 

basis, as the Commission did in the PJM 

proceeding cited by the commenters. 

8. Transmission Curtailments 

1620. In the NOPR, the Commission 

proposed no changes to the pro forma 

OATT with respect to curtailment 

provisions for point-to-point service (set 

forth in sections 13.6 and 14.7) and 

network service (set forth in section 33). 

These provisions establish the terms 

and conditions under which a 

transmission provider may curtail 

service to maintain reliable operation of 

the system. Though several commenters 

claimed in response to the NOI that the 

reasons for transmission curtailments 

are difficult to discern, they did not 

provide sufficient detail to indicate 

whether that difficulty is a result of 

inadequate disclosure regulations, 

inadequate compliance with those 

regulations, or some other reason. 

Therefore, the Commission sought 

further comment on whether requiring 

transmission providers to post 

additional information would improve 

transparency and the ability of 

customers to make use of that 

information. The Commission also 

declined in the NOPR to propose 

generic penalties for improper 

transmission curtailments. 

Comments 

1621. APPA suggests that the 

Commission require transmission 

providers to produce additional 

information regarding firm transmission 

service curtailments, including all 

circumstances and events contributing 

to the need for such firm service 

curtailments, specific services and 

customers curtailed (including the 

transmission provider’s own retail 

loads), and the duration of all such 

curtailments. TAPS also urges the 

Commission to move toward maximum 

transparency and require that sufficient 

information be provided for a customer 

to evaluate whether it has been treated 

fairly as compared to other users of the 

system including the transmission 

provider. TDU Systems suggests that the 

Commission require investigations into 

the need for network upgrades when 

Level 5 Transmission Loading Relief 

(TLR) procedures are repeatedly 

employed. It also suggests that all Level 

5 TLRs be posted on OASIS and filed 

with the Commission. EEI agrees that 

providing customers with information 

on transmission curtailments may help 

to reduce confusion and suspicion 

concerning curtailments and suggests 

the Commission request WEQ (NAESB) 

to develop a more detailed template for 

posting information on curtailments that 

will be more useful to customers. 

1622. Southern and other 

commenters 922 state that sufficient 

information regarding curtailments of 

transmission service is already available 

on OASIS and believe that the existing 

rules requiring transmission providers 

to make curtailment data available on 

OASIS are adequate. Nevada Companies 

request the Commission be very specific 

if it decides to mandate additional 

reporting requirements in order to 

remove the burden of potential 

confidentiality problems from the 

reporting entity. 

1623. Powerex is concerned about 

inconsistent communication and 

curtailment procedures. It recommends 

that the Commission require three 

additional measures including: Early 

notice of curtailment through the use of 

the ‘‘recall’’ function on OASIS; a 

requirement to provide credits for 

curtailed service when non-firm pointto-point transmission service is 

interrupted; and requiring pro rata 

curtailments made prior to the energy 

scheduling and tagging deadline (e.g., 

20 minutes before the operating hour) to 

be based on reservation rather than 

schedule. In its reply comments, Seattle 

states support of pro rata curtailments 

based on reservations. TDU Systems 

recommend that the Commission 

require transmission providers to refund 

transmission charges to curtailed 

customers, to discourage transmission 

providers from overselling their 

systems. On reply, EEI and PNM–TNMP 

urge the Commission to reject the 

proposals to require transmission 

providers to refund transmission service 

charges to curtailed customers. They 

state that transmission providers are 

following ATC calculation procedures, 

but the planning process is not 

structured to overbuild the system to 

ensure that no curtailments occur. They 

also argue that the rate of return 

permitted in existing cost of service 

regulation does not account for the risk 

of loss of curtailment-related revenues. 

Northwest IOUs request the 

Commission examine whether pro rata 

curtailments of transactions to relieve 

transmission constraints unnecessarily 

impose burdens on transmission 

customers, because different 

curtailments on different paths have 

different effectiveness in relieving a 

given transmission constraint. 

1624. Manitoba Hydro notes that 

MISO is the only RTO in the Eastern 

Interconnection that does not redispatch 

when constraints occur on non-market 

to market flows. Manitoba Hydro 

therefore urges the Commission to 

encourage implementation of redispatch 

to the fullest extent before resorting to 

curtailment. Seattle also supports 

modifying the pro forma OATT to 

require reliability redispatch. Seattle 

proposes that redispatch costs should be 

allocated to all classes of customers, and 

transmission providers’ cost recovery 

should be allowed through automatic 

adjustment clause-type formulas to 

ensure all such costs are recovered. It 

suggests that routine maintenance 

outages are resulting in curtailments, 

which is an indication that transmission 

service is oversold. Seattle further 

suggests that transmission providers 

prepare a quarterly incident report for 

redispatch events detailing 

circumstances resulting in the 

redispatch, system status information, 

power transfer distribution factors, 

generator offers for redispatch and other 

information supporting redispatch 

determinations, including the basis for 

selecting generators called for 

redispatch. 

1625. APPA, EEI and others comment 

that the Commission should not impose 

generic penalties for improper 

curtailments, but treat violations on a 

case-by-case basis. To ensure 

compliance with curtailment posting 

information, Southwestern Coop 

suggests that the Commission adopt 

generic penalties for curtailment 

violations, claiming that penalties for 

transmission provider curtailment 

discrimination would provide 

incentives for compliance. 


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923See Order No 888–A at 30,276. In Allegheny 

Power System, Inc., 80 FERC ¶ 61,143 at 61,549 

(1997), the Commission clarified that where a 

transmission provider has not proposed an express 

crediting provision for the interruption of non-firm 

point-to-point customers, the transmission provider 

must compute its bill to an interrupted non-firm 

customer as if the term of service actually rendered 

were the term of service reserved. In other words, 

if a customer with a weekly reservation was 

interrupted after one day, its bill must be computed 

as if it had a daily reservation, and if a customer 

with a daily reservation was interrupted after ten 

hours, its bill must be computed using the hourly 

rate applied to ten hours of service. 

Commission Determination 

1626. The Commission concludes that 

the posting of additional curtailment 

information is necessary to provide 

transparency and allow customers to 

determine whether they have been 

treated in the same manner as other 

transmission system users, including 

customers of the transmission provider. 

A primary goal of this rulemaking is to 

remove opportunities for transmission 

providers to unduly discriminate in 

favor of their own or their affiliates’ use 

of the transmission system. Making 

transparent details concerning 

transmission curtailments so that 

regulators and customers can verify that 

the transmission provider curtailed 

services in accordance with its OATT is 

entirely consistent with this goal. 

Commenters who oppose greater 

curtailment transparency offer no 

convincing evidence to suggest that any 

harm or hardship of doing so outweigh 

the benefits. 

1627. We agree with suggestions for 

the posting of additional curtailment 

information on OASIS and, therefore, 

require transmission providers, working 

through NAESB, to develop a detailed 

template for the posting of additional 

information on OASIS regarding firm 

transmission curtailments. 

Transmission providers need not 

implement this new OASIS 

functionality and any related business 

practices until NAESB develops 

appropriate standards. These postings 

must include all circumstances and 

events contributing to the need for a 

firm service curtailment, specific 

services and customers curtailed 

(including the transmission provider’s 

own retail loads), and the duration of 

the curtailment. This information is in 

addition to the Commission’s existing 

requirements: (1) When any 

transmission is curtailed or interrupted, 

the transmission provider must post 

notice of the curtailment or interruption 

on OASIS, and the transmission 

provider must state on OASIS the 

reason why the transaction could not be 

continued or completed; (2) information 

to support any such curtailment or 

interruption, including the operating 

status of facilities involved in the 

constraint or interruption, must be 

maintained for three years and made 

available upon request to the curtailed 

or interrupted customer, the 

Commission’s Staff, and any other 

person who requests it; and, (3) any 

offer to adjust the operation of the 

transmission provider’s system to 

restore a curtailed or interrupted 

transaction must be posted and made 

available to all curtailed and interrupted 

transmission customers at the same 

time. 

1628. The Commission rejects TDU 

Systems’ proposal to require reports 

filed with the Commission regarding 

Level 5 TLRs or to require transmission 

providers to conduct investigations into 

the need for network upgrades when 

TLR 5 procedures are repeatedly 

employed. TDU Systems’ proposal is 

unnecessary at this time in light of our 

requirement that OASIS templates for 

curtailment information be developed 

that will report occurrences of all levels 

of TLRs. This will enable the 

Commission and customers to monitor 

TLR patterns and frequency. 

Furthermore, the requirements imposed 

in this Final Rule for congestion studies 

as part of the coordinated, open and 

transparent planning requirement will 

allow stakeholders in the transmission 

provider’s planning process to request 

studies of those portions of the 

transmission system where they have 

encountered transmission problems due 

to frequent and recurring constraints. 

1629. The Commission rejects the 

three proposals suggested by Powerex. 

First, it is not necessary to provide early 

curtailment notification through the 

OASIS ‘‘recall’’ function since the 

OASIS currently provides a curtailment 

notification function. Transmission 

providers should continue to use the 

OASIS Schedule Details template to 

post information on the scheduled uses 

of the transmission system and any 

curtailments and interruption thereof. 

Second, with respect to Powerex’s 

request to credit customers when their 

non-firm point-to-point transmission 

service is interrupted, we find it 

unnecessary to modify the pro forma 

OATT to adopt such crediting 

procedures, consistent with our finding 

in Order No. 888–A that proper 

crediting would vary depending on the 

specific rate design a company uses.923

Third, we believe that pro-rating 

curtailments based on reservations 

would have the potential to impair 

reliability since the amount of capacity 

actually curtailed using this approach 

would not address actual power flows 

and, therefore, may be less than 

required to relieve the overloaded 

facility. 

1630. The Commission also rejects 

TDU Systems’ recommendation to 

refund transmission charges to curtailed 

customers as a means of disciplining 

instances of improper curtailments or 

transmission providers’ overselling their 

systems. We also reject proposals to 

remedy improper curtailments through 

refunds of transmission charges to 

curtailed customers or imposing generic 

penalties. Rather, the Commission 

believes that addressing allegations of 

inappropriate curtailment practices or 

transmission providers overselling their 

transmission system are more effectively 

administered by the Commission on a 

case-by-case basis. 

1631. With respect to the proposal to 

require redispatch to be performed to 

the fullest extent prior to curtailments, 

Manitoba Hydro itself notes that the 

proposal is intended to address 

curtailment and redispatch practices 

unique to MISO. Therefore we conclude 

that Manitoba Hydro’s concerns are best 

addressed on a case specific basis. 

1632. Regarding Seattle’s proposal to 

require what it characterizes as 

‘‘reliability redispatch’’ to benefit and be 

paid by all customer classes, we note 

that this proposal would require 

expansion of the network service 

‘‘reliability redispatch’’ provisions to 

apply to point-to-point service as well. 

The network service ‘‘reliability 

redispatch’’ provisions in pro forma 

OATT sections 33.2 and 33.3 were 

established in Order No. 888 to ensure 

comparable reliable service to network 

customers as the service that the 

transmission provider provides to its 

bundled retail load. These redispatch 

procedures further provide for 

redispatch of not just the transmission 

provider’s own resources, but all 

network resources, including those of 

network customers, when required to 

maintain the reliability of the system 

and avoid the need for curtailments. 

Seattle has not demonstrated that its 

proposal to extend ‘‘reliability 

redispatch’’ for point-to-point service is 

required to ensure comparable, not 

unduly discriminatory transmission 

service and has not addressed why 

network customer resources should be 

redispatched for the benefit of point-topoint customer. Accordingly, we 

decline to adopt Seattle’s proposal. We 

discuss redispatch issues more broadly 

in section V.D.1 of this Final Rule. 


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924E.g., Cleveland v. FERC, 773 F.2d 1368, 1376 

(D.C. Cir. 1985). 925See, e.g., Public Serv. Comm’n of N.Y. v. 

FERC, 813 F.2d 448, 454 (D.C. Cir. 1987) (holding 

that the Commission properly excused utilities from 

filing policies or practices that dealt with only 

matters of ‘‘practical insignificance’’ to serving 

customers); Midwest Independent Transmission 

System Operator, Inc., 98 FERC ¶ 61,137 at 61,401 

(‘‘It appears that the proposed Operating protocols 

could significantly affect certain rates and service 

and as such are required to be filed pursuant to 

section 205.’’), order granting clarification, 100 

FERC ¶ 61,262 (2002). 

926Policy Statement on Electric Creditworthiness, 

109 FERC ¶ 61,186 (2004) (Creditworthiness Policy 

Statement). 

927The Commission proposed to require the new 

Attachment L to include the following elements: (1) 

A summary of the procedure for determining the 

level of secured and unsecured credit; (2) a list of 

the acceptable types of collateral/security; (3) a 

procedure for providing customers with reasonable 

notice of changes in credit levels and collateral 

requirements; (4) a procedure for providing 

customers, upon request, a written explanation for 

any change in credit levels or collateral 

requirements; (5) a reasonable opportunity to 

contest determinations of credit levels or collateral 

requirements; and (6) a reasonable opportunity to 

post additional collateral, including curing any 

non-creditworthy determination. 

928E.g., ISO/RTO Council, CAISO, LDWP, MISO/ 

PJM States, PGP, and PNM–TNMP. 

929E.g., CAISO, EEI, MidAmerican, MISO/PJM 

States, Nevada Companies, PJM, Powerex, Santa 

Clara, Suez Energy NA, TDU Systems, and TAPS. 

9. Standardization of Rules and 

Practices 

a. Business Practices 

1633. In Order No. 888, the 

Commission required each public utility 

that owns, controls, or operates facilities 

used for transmitting electricity in 

interstate commerce to file, pursuant to 

section 205 of the FPA, a pro forma 

OATT under which it would provide 

open access transmission services. 

However, certain rules, standards, and 

practices governing the provision of 

transmission service (e.g., public utility 

business practices) are not reflected in 

the pro forma OATT. Only when a 

public utility adopts a rule, standard, or 

practice that significantly affects its 

rates and services has the Commission 

required it to make a filing pursuant to 

FPA section 205 to amend its OATT.924

The Commission has applied this policy 

using a ‘‘rule of reason’’ test.925

NOPR Proposal 

1634. In the NOPR, the Commission 

proposed not to modify its existing 

policy regarding the inclusion of rules, 

standards and practices in a 

transmission provider’s OATTs. The 

Commission expressed concern that 

requiring transmission providers to 

include all of their rules, standards, and 

practices in their OATTs could decrease 

a transmission provider’s flexibility to 

change business practices and respond 

to the requests of its customers. The 

Commission also expressed a belief that 

requiring transmission providers to file 

all of their rules, standards, and 

practices in their OATTs would be 

impractical and potentially 

administratively burdensome. 

1635. The NOPR further noted that 

there is broad consensus that rules, 

standards, and practices not required to 

be included in a transmission provider’s 

pro forma OATT should be posted on 

the transmission provider’s OASIS. The 

Commission agreed and proposed to 

require transmission providers to post 

on OASIS all of their rules, standards, 

and practices that relate to transmission 

services. The Commission sought 

comment on how best to determine 

what ‘‘relates’’ to transmission service to 

facilitate a consistent interpretation and 

to minimize discretion on what rules, 

practice and standards should be posted 

on OASIS. 

1636. On the particular issue of 

creditworthiness and security 

requirements, the Commission 

preliminarily concluded that the mere 

posting of information on OASIS was 

insufficient. The Commission proposed 

that each transmission provider’s OATT 

contain sufficient information about its 

credit process and requirements to 

enable customers to understand the 

information required to demonstrate 

creditworthiness and to determine for 

themselves the general amount and type 

of security they may need to provide in 

order to receive service. The 

Commission therefore proposed to 

amend section 11 of the pro forma 

OATT on creditworthiness to require 

each transmission provider to include 

its creditworthiness and security 

requirements in a new Attachment L to 

its OATT. Consistent with the 

Creditworthiness Policy Statement,926

the Commission proposed to require the 

new Attachment L to include such 

qualitative and quantitative criteria 

necessary to determine the level of 

secured and unsecured credit required, 

with supplementation in a credit guide 

or manual to be posted on OASIS.927

The Commission sought comment on 

whether the proposal is unduly 

burdensome. 

Comments 

Included in Open Access Transmission 

Tariffs 

1637. Many commenters express 

support for the continuation of the 

current Commission policy which 

requires the inclusion in the 

transmission provider’s OATT of only 

those rules, standards and practices that 

significantly affect transmission rates 

and services.928 These commenters 

generally state that any rule, practice, 

term or condition that could result in 

limiting access to transmission services, 

including rates and charges for service, 

should be included in the OATT and 

should be subject to Commission 

scrutiny. Examples given include all 

rules and practices affecting calculation 

of ATC, creditworthiness criteria, and 

rules or practices affecting the 

transmission provider’s regional 

planning process. Commenters argue 

that Commission oversight is necessary 

to ensure that these rates, charges, rules, 

practices, terms or conditions of 

transmission service are reasonable and 

afford comparable treatment for 

wholesale customers. 

1638. Other commenters advocate 

further inclusion of rules, standards and 

practices in the transmission provider’s 

OATT. Morgan Stanley believes that 

business practices manuals should be 

incorporated into each OATT and filed 

with the Commission for approval. 

Morgan Stanley states that if this is not 

required then, at a minimum, each 

OATT should provide for a process to 

use when the transmission provider 

wishes to amend its business practices 

manuals. For example, transmission 

providers should provide notice to all 

affected parties of an intent to make a 

change, a mechanism to receive 

stakeholder feedback on the proposed 

change, and a minimum period of time 

between the final implementation 

decision and the effective date of the 

proposed change (e.g., 30–60 days after 

final decision). Southwestern Coop, 

however, maintains that transmission 

providers should not be allowed to 

change their rules, standards and 

practices that affect the justness and 

reasonableness of OATTs without prior 

Commission review. Southwestern Coop 

states that the Commission should 

require all rules, standards and practices 

relating to transmission services to be 

included in the OATT filed with the 

Commission, because otherwise it 

cannot ensure that jurisdictional rates 

are just and reasonable. 

Posted on OASIS 

1639. Many commenters also express 

support for the proposed requirement 

that all rules, standards and practices 

that are not required to be included in 

a transmission provider’s OATT and 

that affect a transmission provider’s 

provision of transmission service be 

posted on OASIS.929 Commenters 

generally state that these postings will 

allow for increased transparency, while 

affording the transmission provider 

flexibility to make revisions rather than 


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930E.g., APPA, East Texas Cooperatives, Lassen, 

MISO/PJM States, Nevada Companies, NRECA, 

PGP, Powerex, Southern, Suez Energy NA, TANC, 

and TAPS. 931See NOPR at P 456. 

932 16 U.S.C. 831n–4. 

933Citing East Ky. Power Coop., Inc., 114 FERC 

¶ 61,035 at P 56 (2006). 

934E.g., MidAmerican, Southern, PNM–TNMP, 

NorthWestern, and Xcel. 

935E.g., PNM–TNMP, EEI, and MidAmerican. 

936Southern states that it already includes 

creditworthiness and security requirements in its 

having to amend the OATT each time a 

change occurs. 

1640. Powerex argues that the 

transmission provider also should be 

required to post data used to calculate 

ATC, any metrics the Commission 

adopts regarding the transmission 

provider’s performance of system 

impact and facilities studies, 

information concerning both planned 

and unplanned transmission outages, 

and a transmission provider’s business 

practices, tariff, organizational charts 

and job descriptions of its employees. 

1641. Southern takes issue with the 

use in the NOPR of the phrase ‘‘all of 

their rules, standards and practices,’’

stating that language suggests that a 

transmission provider might be required 

to reduce each detail of its business 

practices to writing, which could be 

overly burdensome. In addition, 

Southern believes that any rule relating 

to posting requirements on OASIS 

should have certain mechanisms to 

allow the transmission provider to 

deviate from posted practices when 

necessary. In contrast, ELCON states 

that any rule, standard or practice used 

by the transmission provider and any of 

its employees to approve or disapprove 

a request for service should be 

committed to writing and posted. 

Similarly, TranServ argues that 

transmission providers should be 

required to post on OASIS any criteria 

applied by the transmission provider to 

any attribute of a transmission or 

ancillary service request for the purpose 

of determining whether the service 

request should be approved or denied. 

1642. Northwest IOUs suggests that 

the Commission should adopt a ‘‘rule of 

reason’’ test for matters required to be 

posted on the OASIS similar to the test 

applied to matters required to be 

included in the OATT. 

Creditworthiness 

1643. Several commenters support the 

inclusion of a separate Attachment L to 

the pro forma OATT outlining 

creditworthiness requirements, asserting 

that Attachment L will standardize 

credit procedures and security 

requirements and increase 

transparency.930 Suez Energy NA states 

that the proposal is not unduly 

burdensome, that the procedures 

proposed are not different from the 

Creditworthiness Policy Statement or 

the procedures already imposed in 

individual cases, and that the 

Commission is merely proposing to 

apply an existing requirement in a nondiscriminatory manner. 

1644. Other commenters propose 

modifications to the credit-related 

proposals set forth in the NOPR. TAPS 

urges the Commission to require the 

transmission provider to adopt a twopart creditworthiness assessment in 

order to facilitate non-burdensome and 

fair assessment of creditworthiness. 

TAPS recommends that a standard 

similar to the Florida Power Corp. 

OATT be applied, which provides that 

customers with ‘‘satisfactory long-term 

payment history’’ and a minimum credit 

rating of Baa2 (Moody’s) or BBB (S&P) 

would not have to post any credit 

security. If a customer fails to meet the 

threshold test, TAPS states that the 

transmission provider would perform a 

transparent credit assessment that is 

consistent with the Commission’s 

Creditworthiness Policy Statement and 

the credit policies developed for use in 

regional transmission organizations 

such as MISO and SPP. According to 

TAPS, since quantitative measures 

sometimes understate public power 

creditworthiness, transmission 

providers will need to weigh qualitative 

factors more heavily than quantitative 

factors in assessing public power 

creditworthiness. For public entities 

that fail the threshold test, TAPS states 

that transmission providers should use 

outstanding bond indebtedness as a 

proxy for tangible net worth for those 

entities whose energy and transmission 

service payments receive priority over 

bond payments. 

1645. PJM generally agrees with the 

creditworthiness proposals, except for 

inclusion in the OATT of the actual 

detailed algorithms used to calculate 

credit scores, stating that those 

algorithms, as the Commission 

recognized,931 may change over time. In 

PJM’s view, requiring all such changes 

to be approved by the Commission 

would be unnecessarily burdensome to 

both the Commission and the 

transmission provider. PJM 

recommends that the overall framework 

of the credit determinations be included 

in the OATT, while the detailed 

algorithms be posted on OASIS to meet 

transparency goals. PJM also 

recommends that the Commission 

accept, as an option, a regularly-updated 

posting on the transmission provider’s 

Web site of each customer’s available 

credit and collateral requirement as 

sufficient notification for most changes 

in credit available and credit 

requirements. PJM further recommends 

that only significant and sudden 

reductions in credit available (for 

example, those greater than 25 percent 

within a one-month period) be subject 

to an active notification requirement. 

1646. TVA recommends the 

Commission consider two fundamental 

principles as it standardizes 

creditworthiness terms and conditions. 

First, as long as qualitative factors are 

part of the equation (and TVA agrees 

that they should be), TVA states that 

certain subjective judgments by the 

transmission provider will be required. 

TVA encourages the Commission to 

provide guidance on appropriate criteria 

to consider in making these judgments, 

but not to remove entirely from the 

process the flexibility necessary for 

individual assessments of customer 

creditworthiness. Second, TVA states 

that transmission providers may have to 

impose different security requirements 

as a result of differences in statutes, 

regulations, or other legal requirements. 

For example, TVA states that its ability 

to incur debt is limited by section 15d(a) 

of the Tennessee Valley Authority 

Act 932 and, therefore, it may need to 

impose security requirements that are 

stricter than those of a public utility, as 

the Commission has previously 

recognized.933 TVA requests that the 

final rule respect these differing legal 

obligations and provide corresponding 

flexibility in credit decisions among 

transmission providers. 

1647. A number of commenters 

oppose the Commission’s proposed 

creditworthiness policy.934 In general, 

these commenters believe that each 

transmission provider should have the 

flexibility to make and change 

creditworthiness procedures without 

the delay of obtaining Commission 

approval. They also argue that the 

Commission’s goal of transparency 

could be better achieved by requiring 

the posting of a transmission provider’s 

creditworthiness policy on OASIS.935

Xcel and MidAmerican assert that the 

Commission’s proposal would decrease 

a transmission provider’s ability to 

timely respond to changing market and 

financial conditions and, therefore, 

creditworthiness and security 

requirements should simply be posted 

on OASIS. Southern believes that the 

Commission should permit but not 

require transmission providers to file 

their creditworthiness and security 

procedures as part of their OATTs.936


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OATT since the Commission issued its 

Creditworthiness Policy Statement. 

937California Independent System Operator 

Corp., 107 FERC ¶ 61,329 at P 21–22 (2004); see 

also Southwest Power Pool, Inc., 112 FERC ¶ 61,303 

at P 25 (requiring that the SPP OATT provide 

sufficient information for market participants to 

fully understand SPP’s implementation of an 

imbalance market), reh’g denied, 113 FERC ¶ 61,115 

(2005); PJM Interconnection, L.L.C., 104 FERC 

¶ 61,124 at P 61 (requiring PJM to place all 

procedures, standards and requirements for 

proposing that a transmission owner construct a 

specific upgrade, and all procedures for charging 

customers, in its tariff, not in its manuals), order on 

reh’g, PJM Interconnection, L.L.C., 105 FERC 

¶ 61,123 (2003). 

938See, e.g., Order No. 889 at 31,588–89; Open 

Access Same-Time Information Systems, Order No. 

605, 64 FR 34117 (Jun. 25, 1999), FERC Stats. and 

Regs. ¶ 31,075 (1999); Order No. 676 at P 79. 939 If a particular rule, standard or practice 

conflicts with an OATT provision, the OATT of 

course shall govern in all circumstances. Moreover, 

as noted in the NOPR, we emphasize that posting 

rules, practices and standards—in lieu of filing such 

practices with the Commission as part of the 

transmission provider’s pro forma OATT—neither 

insulates a transmission provider from complaints 

nor confers a just and reasonable presumption. We 

encourage customers to call the Commission’s 

Enforcement Hotline with complaints about the 

application of such rules, standards and practices 

should they experience problems with their 

transmission providers. To the extent customers are 

not satisfied with responses from their transmission 

provider, they should contact the Commission’s 

Enforcement Hotline via telephone (202) 502–8390, 

toll-free 1–888–889–8030, fax (202) 208–0057, or at 

http://www.ferc.gov/cust-protect/enforce-hot.asp. 

940With respect to the business practices 

developed by NAESB, there may be certain 

copyright restrictions that limit the transmission 

provider’s ability to post those practices on its own 

Web site. In such instances, we expect that the 

transmission provider will reference any NAESB 

practices it uses and provide a link on its public 

Web site to the NAESB Web site in order to provide 

interested parties with a means to access the 

copyrighted material. 

941The circumstances and manner in which a 

transmission provider exercises its discretion under 

its OATT must be posted in accordance with 18 

CFR 37.6(4). 

Southern also asks that the Commission 

allow a transmission provider, in its 

compliance filing, to request a 

determination that its current 

creditworthiness policies and practices 

are acceptable under the new 

Commission policies. Similarly, ISONew England states that this rulemaking 

should not modify the ISO-New 

England Financial Assurance and 

Billing Policies, which are already on 

file with the Commission. 

1648. CAISO states that although the 

NOPR requirements concerning credit 

and security requirements do not appear 

unduly burdensome, it is concerned that 

the Commission may apply these 

requirements in a manner that will 

impose an undue burden on 

transmission providers and effectively 

eliminate the ability of transmission 

providers to supplement basic elements 

with a credit guide or manual. CAISO 

and MidAmerican further state that 

there is no legitimate reason to treat 

credit policies and procedures any 

differently than the other rules, 

practices and standards that the 

Commission permits to be included on 

OASIS and does not require to be filed 

as part of the tariff. Santa Clara 

recommends that if the Commission 

decides to require creditworthiness and 

security policies to be posted on OASIS 

rather than included in the OATT, then 

it should require at least a 30-day notice 

period for changes in the credit policies. 

Commission Determination 

1649. The Commission adopts the 

NOPR proposal to continue to require 

only those rules, standards, and 

practices that significantly affect 

transmission service be incorporated 

into a transmission provider’s OATT. 

The Commission further affirms the use 

of a ‘‘rule of reason’’ to determine what 

rules, standards, and practices 

significantly affect transmission service 

and, as a result, must be included in the 

transmission provider’s OATT. 

1650. The ‘‘rule of reason’’ test has 

arisen primarily with respect to 

protocols or operating procedures used 

by RTOs and ISOs. For example, the 

Commission has held that, while 

MISO’s business practices manuals 

implicate the Commission’s jurisdiction 

because they generally involve ‘‘the 

installation, operation, or use of 

facilities for the transmission or delivery 

of power in interstate commerce,’’ they 

do not require an FPA section 205 filing 

because ‘‘they mostly involve general 

operating procedures.’’ In other cases, 

the facts have required the filing of the 

rule, standard or practice. For example, 

CAISO proposed to post certain 

technical, operational and business 

standards related to dynamic scheduling 

on its Web site and include only the 

rates under its OATT. In that instance, 

the Commission found that the details 

contained in the standards were 

practices that could significantly affect 

the terms and conditions of service and, 

therefore, under the Commission’s ‘‘rule 

of reason’’ must be filed under section 

205 of the FPA.937

1651. Comments received in response 

to the NOPR confirm that there is broad 

support for the Commission’s existing 

practice, requiring only those rules, 

standards, and practices that 

significantly affect transmission service, 

and the use of the ‘‘rule of reason’’ test 

to identify those rules, standards, and 

practices. The Commission disagrees 

with parties arguing that all of a 

transmission provider’s rules, standards, 

and practices should be incorporated 

into its OATT. We believe that requiring 

transmission providers to file all of their 

rules, standards and practices in their 

OATTs would be impractical and 

potentially administratively 

burdensome. 

1652. The Commission instead 

requires transmission providers to post 

on their public Web sites all rules, 

standards, and practices that relate to 

transmission service and provide a link 

to those rules, standards, and practices 

on OASIS. We conclude that it would 

not be appropriate to place the rules, 

standards, and practices only on OASIS 

as some transmission providers use 

certificates to restrict access to their 

OASIS sites. By providing a link on 

OASIS to the rules, standards, and 

practices that are otherwise publicly 

posted, the Commission ensures that all 

potential customers will have access to 

the information necessary for them to 

understand the terms and conditions of 

service. We amend section 4 of the pro 

forma OATT to expressly establish this 

posting requirement. 

1653. We note that we already require 

certain rules and practices to be posted 

on OASIS.938 We find that it is now 

necessary to also require that all rules, 

standards or business practices that 

relate to the terms and conditions of 

transmission service, and how that 

transmission service is provided to 

customers, to be detailed, clearly stated 

on the transmission provider’s public 

Web site, with a link to this information 

on OASIS.939 We emphasize that this 

requirement applies to all such rules, 

standards, and practices, currently 

written or otherwise.940 While we 

acknowledge this requirement will 

result in some burden to transmission 

providers, we find that this approach is 

necessary to provide greater 

transparency and mitigate the potential 

for undue discrimination against 

customers taking service under the 

transmission provider’s OATT. Further, 

our holding is not intended to eliminate 

all discretion under the pro forma 

OATT; rather, we recognize that certain 

tariff provisions require consideration of 

the specific facts and circumstances 

related to particular service requests.941

We merely require that, if the 

transmission provider uses standards, 

rules or business practices to administer 

its OATT, such standards, rules or 

business practices must be available for 

public inspection. Moreover, we note 

that our actions here are consistent with 

actions we have taken in recent 

proceedings. For example, the 

Commission has required that certain 

business practices manuals be posted 


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942See, e.g., Midwest Independent Transmission 

System Operator, Inc., 108 FERC ¶ 61,163 at P 658, 

order on reh’g, 109 FERC ¶ 61,157 (2004), order on 

reh’g, 111 FERC ¶ 61,043, order on reh’g, 112 FERC 

¶ 61,086 (2005); see also PJM Interconnection, 

L.L.C., 81 FERC ¶ 61,257 at 62,267 (1997) (finding 

no reason to require filing of the PJM Manuals but 

requiring that such manuals be available for public 

inspection on a permanent basis), order on reh’g, 92 

FERC ¶ 61,282 (2000). 943As part of their business practice amendment 

procedures, transmission providers may adopt such 

additional procedures they deem appropriate, such 

as opportunities for comment to proposed changes 

to rules, standards, and practices. 

944As with new Attachment K to the pro forma 

OATT, regarding transmission planning, we 

acknowledge that some transmission providers may 

already have attachments to their OATTs labeled 

with the letter ‘‘L,’’ in which case transmission 

providers are free to label their credit procedures 

OATT attachment with the next available letter. 

and made available for public view on 

a permanent basis.942 As in those cases, 

we find that making rules, standards, 

and practices readily accessible will 

serve as a tool to supplement each 

transmission provider’s OATT and 

facilitate fair and open access to the 

transmission grid. 

1654. To provide guidance to the 

transmission providers as to whether a 

particular rule, standard, or practice 

‘‘relates to’’ transmission service, and 

therefore warrants posting, the 

Commission believes the MAPP Policies 

and Procedures for Transmission 

Operations manual is a good example of 

the type of information that relates to 

the terms and conditions of 

transmission service. For example, the 

MAPP manual sets forth information 

supplementing its OATT pertaining to 

(1) transmission service requests on the 

MAPP OASIS site, (2) the retraction of 

an accepted or counteroffer 

transmission request, (3) timing 

requirements for transmission service 

requests, (4) methods to accommodate a 

firm transmission request with 

redispatch, and (5) transmission service 

charge implementation procedures. 

Other examples include detailed 

information regarding tagging, 

scheduling, billing and other matters 

provided in other RTO manuals. This is 

the type of information that clearly 

relates to transmission service and 

therefore must be reduced to writing 

and publicly posted. 

1655. We also agree with requests to 

require a transparent process for 

amending rules, standards, and 

practices previously posted by a 

transmission provider. We therefore 

require each transmission provider also 

post on its public Web site (with a 

corresponding link on OASIS) a 

statement of the process by which the 

transmission provider will amend these 

rules, standards, and practices that are 

accessible via OASIS. As part of this 

process, the transmission provider must 

specify a mechanism to provide 

reasonable notice of any proposed 

changes to a posted business practice 

and the respective effective date of such 

change.943 We amend section 4 of the 

pro forma OATT to formalize this 

posting requirement and obligate 

transmission providers to follow the 

amendment procedures specified by the 

transmission provider. As with the 

requirement to post the underlying 

standards, rules and practices, we 

believe the amendment procedures 

required here will increase transparency 

and help minimize opportunities for 

undue discrimination. 

1656. The Commission also adopts 

the NOPR proposal and amend the pro 

forma OATT to include a new 

Attachment L.944 We find that the 

transmission provider’s basic credit 

standards significantly affect 

transmission service and, therefore, 

must be included in the pro forma 

OATT. This will ensure that all 

customers have clear information as to 

the credit process and standards used by 

a transmission provider to grant or deny 

transmission service and, in turn, will 

serve to prevent undue discrimination 

and eliminate a potentially significant 

barrier to entry in the provision of 

service. Most importantly, by making 

Attachment L a part of the pro forma 

OATT, customers will have an 

opportunity to comment on any changes 

to the standards proposed by a 

transmission provider in a rate filing 

with the Commission. 

1657. To that end, each transmission 

provider’s Attachment L must specify 

the qualitative and quantitative criteria 

that the transmission provider uses to 

determine the level of secured and 

unsecured credit required. Attachment 

L must also contain the following 

elements: (1) A summary of the 

procedure for determining the level of 

secured and unsecured credit; (2) a list 

of the acceptable types of collateral/ 

security; (3) a procedure for providing 

customers with reasonable notice of 

changes in credit levels and collateral 

requirements; (4) a procedure for 

providing customers, upon request, a 

written explanation for any change in 

credit levels or collateral requirements; 

(5) a reasonable opportunity to contest 

determinations of credit levels or 

collateral requirements; and (6) a 

reasonable opportunity to post 

additional collateral, including curing 

any non-creditworthy determination. 

We will allow the transmission provider 

to supplement Attachment L with a 

credit guide or manual to be posted on 

OASIS. 

1658. We disagree with commenters 

that claim requiring this information in 

an attachment to each transmission 

provider’s OATT will hinder the 

transmission provider’s ability to timely 

respond to changing market and 

financial conditions. Because 

Attachment L requires only a summary 

of credit requirements and other 

information, we expect the need to 

revise Attachment L will occur 

infrequently. As suggested by PJM, 

detailed information, such as the 

algorithms used by the transmission 

provider to determine credit scores, can 

be posted on OASIS along with other 

information that relates to the provision 

of transmission service. Thus, the 

requirement we are imposing should not 

be overly burdensome. 

1659. At the same time, we agree that 

transmission providers need flexibility 

in determining credit requirements in 

light of qualitative and quantitative 

factors, as we recognized in the NOPR 

and the Creditworthiness Policy 

Statement. We believe the requirements 

adopted in this Final Rule allow for 

such flexibility. By requiring 

transmission providers to consider both 

quantitative and qualitative factors, the 

particular circumstances surrounding 

public power entities can be recognized. 

We agree, moreover, with TVA that the 

transmission provider’s credit policies 

must be consistent with its legal 

obligations and expect that interested 

parties will bring any legal conflicts to 

our attention on review of the 

transmission provider’s compliance 

filing. 

1660. With regard to requests to find 

existing credit policies consistent with 

the requirements of the Final Rule, all 

transmission providers will be required 

to demonstrate compliance with all 

aspects of the Final Rule either by 

implementing the reforms adopted 

today or showing that departures are 

consistent with or superior to the terms 

and conditions of the pro forma OATT, 

as modified by this Final Rule. The 

procedural mechanisms for making such 

a showing provided for in section IV.C 

above give transmission providers the 

opportunity to demonstrate that 

retention of their existing credit 

practices is appropriate. 

1661. Finally, with regard to Santa 

Clara’s request to require the 

transmission provider to provide at least 

a 30-day notice period for changes in 

creditworthiness and security policies 

that are posted on OASIS, we explain 

above that each transmission provider 

must identify and incorporate a specific 

process in its OATT for amending 

business practices that are posted on 

OASIS. Such practices include those 


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945Order No. 888–B at 62,081 

946E.g., Southern, EEI, and Northwest IOUs. 

947Citing Article 18, Large Generator 

Interconnection Agreement; ANR Pipeline Co., 98 

FERC ¶ 61,218, order on tariff filing, 100 FERC 

¶ 61,132 (2002). 

948Citing Southwest Power Pool, Inc., 112 FERC 

¶ 61,100 at P 39 (2005). 949Citing Order No. 888–A at 30,301. 

that describe and implement its 

creditworthiness and security policies. 

b. Liability and Indemnification 

1662. In Order No. 888, the only 

liability provisions included in the pro 

forma OATT related to force majeure 

and indemnification.945 Section 10.1 of 

the pro forma OATT provides that 

neither the transmission provider nor 

the transmission customer will be 

considered in default as to any 

obligation under the tariff if prevented 

from fulfilling the obligation due to an 

event of force majeure. A party whose 

performance under the tariff is hindered 

by an event of force majeure, however, 

is required to make all reasonable efforts 

to perform its obligations under the 

tariff. With respect to indemnification, 

under section 10.2 of the pro forma 

OATT, the transmission customer 

indemnifies the transmission provider 

against third party claims arising from 

the transmission provider’s performance 

of its obligations under tariff on behalf 

of the transmission customer, except in 

cases of negligence or intentional 

wrongdoing by the transmission 

provider. 

(1) Force Majeure 

Comments 

1663. Santa Clara queries whether the 

Commission intended to make the 

transmission provider’s performance of 

its obligations less burdensome by using 

the phrase ‘‘all reasonable efforts’’

instead of ‘‘due diligence’’ in the force 

majeure provision in section 10.1 of the 

pro forma OATT is. In either case, Santa 

Clara requests the Commission to 

consider the use of the most stringent 

term when addressing a transmission 

provider’s obligation to perform under 

its tariff. 

Commission Determination 

1664. The Final Rule retains the 

current ‘‘all reasonable efforts’’ standard 

in the force majeure provision. Santa 

Clara does not explain how the ‘‘all 

reasonable efforts’’ standard may be 

more or less stringent than the ‘‘due 

diligence’’ standard. Further, as the 

Commission explained in Order No. 

888, this protection against unexpected 

and unpredictable events is 

appropriately made available to both the 

transmission provider and transmission 

customer. We therefore find that the 

clarification requested by Santa Clara is 

unnecessary. 

(2) Indemnification/Limitation of 

Liability 

Comments 

1665. Several commenters 946 urge the 

Commission to change the 

indemnification provision to protect 

transmission providers from liability 

except in the case of gross negligence or 

intentional misconduct, thereby 

exempting the transmission provider 

from liability for acts of ordinary 

negligence. These commenters also 

request that the Commission add to the 

pro forma OATT a new provision 

clarifying that the transmission provider 

would not be liable to any transmission 

customer or third party for direct, 

incidental, consequential, indirect, or 

punitive damages arising from services 

provided under the tariff, except in 

cases of gross negligence or intentional 

misconduct (in which case, EEI, and 

Northwest IOUs propose, liability 

would be limited to direct damages). 

These commenters note that the 

Commission has allowed transmission 

providers this protection in the tariffs of 

MISO, PJM, ISO New England, SPP, and 

their member transmission owners and 

generators, but it has not fully explained 

its basis for treating non-RTO member 

transmission providers differently from 

RTOs and ISOs. EEI further notes that 

the Commission accepted similar 

liability protection in the Large 

Generator Interconnection Agreement 

(‘‘LGIA’’) and in natural gas pipeline 

tariffs.947 EEI requests that this liability 

limitation be added to the pro forma 

transmission service agreement that 

would apply to transmission customers 

acting in good faith to carry out the 

directives of a transmission provider. 

1666. With respect to third party 

indemnification, EEI notes that the 

Commission reasoned in SPP that, even 

though a broader liability limitation 

would relieve a transmission provider 

from liability for ordinary negligence, 

that provision only applies to 

transmission customers under the tariff. 

EEI states that there are many other 

entities that could initiate legal action 

against the transmission provider in 

connection with the provision of 

transmission service, thereby making an 

adequate indemnification provision in 

the pro forma OATT necessary for the 

same reasons as the limited liability 

provision.948

1667. EEI contends that the addition 

of the Commission’s new EPAct 2005 

authority to establish mandatory 

reliability standards to provide open 

access transmission service to all 

customers, regardless of their risk 

profile, makes it an appropriate time to 

revisit the liability provisions in the 

OATT. According to EEI, a limitation on 

liability in the pro forma OATT should 

be viewed as a necessary element of the 

implementation of the Commission’s 

reliability authority. Because 

transmission providers cannot deny 

service to particular customers based on 

the risk of potential damages, EEI and 

Southern assert that all transmission 

providers should be protected from 

certain risks associated with this 

obligation to serve. EEI argues that 

increased protection from liability 

would lower the cost of capital for new 

transmission projects and promote the 

expansion of transmission 

infrastructure. EEI further argues that 

the technological complexity of modern 

utility systems and the potential for 

service interruptions unrelated to 

human errors justify liability 

limitations. According to EEI, a 

limitation on liability to direct damages 

puts the risk on those customers with 

special reliability needs, rather than 

spreading the risk among all customers. 

1668. EEI notes that the Commission 

has denied requests for exemptions from 

liability for ordinary negligence in the 

indemnification provision on the 

grounds that liability and 

indemnification were ‘‘separate 

issue[s]’’ and that transmission 

providers seeking liability protections 

could rely on state laws.949 EEI argues, 

however, that an OATT and the 

accompanying service agreement 

constitute a contract between the 

transmission provider and the customer 

that is established pursuant to federal 

law and, as a result, it is not at all clear 

that a state law limitation on liability 

would apply. Southern asserts that 

adopting liability limits would provide 

uniformity, certainty, and reduce risk 

since reliance on state law is an issue 

not free from doubt. 

1669. Entegra argues on reply that the 

NOPR did not contemplate any 

modification to these provisions of the 

pro forma OATT and neither EEI nor 

Southern has established a nexus 

between such a modification and the 

goals set forth in the NOPR. TDU 

Systems on reply similarly argue that 

EEI’s request is outside the scope of the 

rulemaking and neither EEI nor 

Southern show a change in 

circumstance justifying a new limitation 


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950See Entegra Reply (citing Southern Company 

Services, Inc., 113 FERC ¶61,239 (2005)). 951See Order No. 888–A at 30,301 and Order No. 

888–B at 62,081 (section 10.2 of the pro forma 

OATT). 

952Order No. 888–A at 30,301. 

953Order No. 888–B at 62,081. 

954See, e.g., Northeast Utilities Services Co., 111 

FERC ¶ 61,333 (2005) (Northeast Utilities). 

955Order No. 888 at 31,765. 

956Order No. 2003 at P 636; Order No. 2003–A 

at 31,162. 

957Policy Statement on Matters Related to Bulk 

Power System Reliability, 107 FERC ¶ 61,052 (2004) 

(Reliability Policy Statement). 

958Reliability Policy Statement at P 40 (citations 

omitted). 

959 112 FERC ¶ 61,100 at P 39 (2005). 

on liability. Immunizing transmission 

providers from these liability risks, TDU 

Systems contend, would simply transfer 

risk to customers that have no control 

over the transmission provider’s 

negligence. Entegra and TDU Systems 

further argue that Southern previously 

sought the same relief in a tariff filing 

rejected by the Commission less than a 

year ago, stating that the Commission 

thus already rejected the notion that 

Southern was similarly situated to the 

RTOs and ISOs that have this 

protection.950 Entegra notes that 

Southern did not seek rehearing of that 

order and its comments here are 

therefore an impermissible collateral 

attack on a final Commission order. As 

for the argument regarding EPAct 2005, 

TDU Systems note that the Commission 

presumably was aware of its new 

reliability authorities when it issued the 

Southern order four months after EPAct 

was enacted. 

1670. TDU Systems also point out that 

the tariff language proposed by EEI 

would not protect a transmission 

customer from being sued by a third 

party for the negligence or willful 

misconduct of the transmission 

provider. In such lawsuits, TDU 

Systems claim, a third party would not 

be limited to direct damages. According 

to TDU systems, any indemnification as 

between the transmission provider and 

the transmission customer that is 

limited to direct damages would leave 

the customer holding the bag for the 

indirect damages caused by the 

transmission provider’s negligence or 

willful misconduct. 

Commission Determination 

1671. We will retain the current 

liability protections in the pro forma 

OATT for the same reasons that the 

Commission has rejected similar past 

proposals. While the Commission 

explained in Order Nos. 888–A and 

888–B that the pro forma tariff was not 

intended to address liability issues, as 

EEI notes, the Commission stated that 

liability was a separate issue from 

indemnification.951 The Commission 

further explained that transmission 

providers were not precluded from 

relying on state laws that protected 

utilities or others from claims founded 

in ordinary negligence.952 The 

Commission declined to adopt a 

uniform federal liability standard and 

decided that, while it was appropriate to 

protect the transmission provider 

through force majeure and 

indemnification provisions from 

damages or liability when service is 

provided by the transmission provider 

without negligence, it would leave the 

determination of liability in other 

instances to other proceedings.953

1672. On the issue of a negligence 

standard for the indemnification 

provision, we decline to depart from our 

policy set forth in Order No. 888, as 

affirmed in Order No. 888–A and 

subsequent orders.954 In Order No. 888, 

the Commission stated: 

We have limited the indemnification 

portion of the provision so that it is now only 

the transmission customer who indemnifies 

the transmission provider from the claims of 

third parties. The customer is taking service 

from the transmission provider and may 

appropriately be asked to bear the risks of 

third-party suits arising from the provision of 

service to the customer under the tariff. We 

find that this new indemnification provision 

would be too strict if it required customers 

to indemnify transmission providers even in 

cases where the transmission provider is 

negligent. Accordingly, the revised provision 

provides that the customer will not be 

required to indemnify the transmission 

provider in the case of negligence or 

intentional wrongdoing by the transmission 

provider.955

1673. The Commission subsequently 

addressed this issue in Northeast 

Utilities. There, the Commission found 

that a broader customer indemnification 

obligation that would include ordinary 

negligence would not give any incentive 

to the transmission provider to avoid 

negligent actions. In Northeast Utilities, 

the Commission explained again why it 

permitted a gross negligence exception 

in the pro forma LGIA section 18.1 in 

order to further limit the transmission 

provider’s liability. As the Commission 

explained in Order No. 2003, 

interconnection warrants a different 

standard because it presents a greater 

risk of liability than exists for the 

provision of transmission service. The 

Commission further found that because 

risk exposure can increase 

interconnection costs, a broader 

indemnity standard is appropriate in the 

interconnection context.956

1674. Further, unlike Order No. 888 

in which the transmission customer 

indemnifies the transmission provider, 

in Order No. 2003 the indemnity 

provision is expressly bilateral. In Order 

No. 2003 the interconnecting generator 

and the transmission provider each 

indemnifies the other from all damages 

to third parties arising under the LGIA 

from conduct on behalf of the 

indemnifying party, except in cases of 

gross negligence. Given that the 

indemnification provision in the pro 

forma LGIA is bilateral, in contrast to 

the pro forma OATT, it is reasonable to 

permit a gross negligence standard in 

the case of an interconnection. 

1675. We also reject commenters’

assertions that the liability standard the 

Commission has approved for RTOs/ 

ISOs and gas pipelines is appropriate for 

other transmission providers. In the 

Reliability Policy Statement,957 the 

Commission stated that it would 

consider, on a case-by-case basis, 

proposals by public utilities to amend 

their OATTs to include limitations on 

liability. The Commission further noted 

that while this issue has not been 

resolved on a standardized basis, the 

Commission has entertained RTO 

transmission providers’ specific 

proposals to amend their OATTs to 

include provisions addressing 

limitations on liability.958

1676. In subsequent orders, the 

Commission found that the gross 

negligence and intentional wrongdoing 

indemnification and liability standard is 

appropriate for RTOs and ISOs. 

However, the Commission has declined 

to extend this protection to all 

transmission providers. In Southwest 

Power Pool, Inc., the Commission 

explicitly stated ‘‘that our acceptance 

here of the gross negligence and 

intentional wrongdoing indemnity 

standard is limited to SPP, in its role as 

an RTO, and its TOs; we do not intend 

to extend such protection to all 

transmission providers.’’ 959 In Southern 

Company Services, Inc., the 

Commission stated that: 

Having considered Southern Companies’

proposed limitation on liability and 

indemnification provisions pursuant to our 

Reliability Policy Statement cited above, we 

find that Southern Companies have not 

shown that they are similarly situated to the 

RTOs/ISOs they cite in support. While 

Southern Companies claim that they ‘‘may 

not be protected by any State-regulated 

limitations on liability,’’ Southern 

Companies offer no evidence to support this 

concern. The Commission has provided such 

liability protection to RTOs/ISOs because 

they were created by and solely regulated by 

the Commission, and otherwise would be 

without limitations on liability. Southern 

Companies have proffered no evidence of any 


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960 113 FERC ¶ 61,239 at P 7 (2005). 961Order No. 888–A at 30,286 and 30,366. 

962Section 30.4 as proposed in the NOPR 

provides, in relevant part, that ‘‘[t]he Network 

Customer shall not operate its designated Network 

Resources located in the Network Customer’s or the 

Transmission Customer’s Control Area such that the 

output of those facilities exceeds its designated 

Network Load, plus Non-Firm Sales delivered 

pursuant to Part II of the Tariff, plus losses.’’

change in circumstances vis-a`-vis their 

liability exposure post-Order No. 888.960

1677. Commenters offer no new 

arguments that demonstrate that they 

are unable to rely on state laws, i.e., the 

state laws provide inadequate 

protection. While EEI and Southern 

assert that there is uncertainty in 

whether state law on liability would 

apply to a service agreement between a 

transmission provider and a 

transmission customer, we note that 

neither provide any evidence that 

transmission providers are actually 

precluded from relying on state law for 

liability protection. EEI and Southern 

thus fail to show that the potential for 

a legal and regulatory gap is so great as 

to warrant inclusion of liability 

protections in the pro forma OATT for 

all transmission providers. In this 

regard, the Commission also finds 

without merit assertions that increased 

liability protections in the pro forma 

OATT should be viewed as a necessary 

element of the implementation of the 

Commission’s reliability authority. As 

none of the arguments proffered by 

commenters persuade us to change our 

policy regarding liability protections 

applicable to non-RTO and non-ISO 

transmission providers, we decline to 

modify the liability protections in the 

pro forma OATT. 

10. OATT Definitions 

1678. In order to support the reforms 

adopted in this Final Rule and 

otherwise clarify the requirements of the 

pro forma OATT, the Commission adds 

and amends various definitions in the 

pro forma OATT, as set forth below. 

a. Affiliate 

NOPR Proposal 

1679. In the NOPR, the Commission 

proposed a new definition of Affiliate 

incident to the proposed change to the 

pricing of reassigned capacity. 

Comments 

1680. Some commenters request 

clarification that the proposed 

definition of Affiliate would not apply 

to transmission-only cooperatives or 

independent entities such as RTOs. 

NRECA asserts that in Order No. 2004–

A, the Commission concluded that 

‘‘[g]eneration and transmission 

cooperatives (G&T) are not subject to the 

Standards of Conduct consistent with 

the policies established under Order No. 

888.’’ NRECA asks for confirmation that 

distribution and generation and 

transmission cooperatives will not be 

considered affiliates of each other for 

OATT and Standards of Conduct 

purposes because recent pleadings 

reveal that there continues to be 

confusion about this definition. 

TranServ asks for clarification of the 

application of the definition of 

‘‘affiliate’’ with respect to a merchant 

affiliate of a transmission provider that 

has turned over tariff administration 

functions to an ISO, RTO, or other 

independent entity. PNM–TNMP 

suggests that the definition of Affiliate 

be expanded or clarified to encompass 

divisions of an entity that operate as a 

functional unit. PNM–TNMP asserts 

that such a change would make clear 

that an Affiliate includes not only 

separate legal entities, but also may 

apply to divisions and functional units 

within the entity. 

Commission Determination 

1681. As discussed in section V.C.4, 

the Commission lifts the price cap on 

reassigned transmission capacity for all 

transmission customers, regardless of 

affiliation with the transmission 

provider. It is therefore no longer 

necessary to define an affiliate for 

purposes of that provision. The 

Commission nonetheless adopts the 

proposed definition of Affiliate to 

implement the reforms associated with 

distribution of operational penalties 

discussed in section V.C.5.b. 

1682. With regard to the request that 

we clarify that an Affiliate does not 

apply to transmission-only cooperatives, 

we agree with NRECA that the 

Commission made clear in Order No. 

888–A that there was no corporate 

affiliation between G&T cooperatives 

and their member distribution 

cooperatives.961

1683. TranServ requests clarification 

regarding the use of the term ‘‘affiliate’’

in the context of a transmission owner 

that has turned over operational control 

of its transmission facilities to an RTO, 

ISO, or to an independent entity. We 

clarify that, for purposes of the 

distribution of penalties, if such 

transmission owner is not required to be 

a transmission provider under a 

Commission-approved tariff, the 

merchant affiliate of such transmission 

owner would not be considered to be an 

‘‘affiliate’’ of the RTO, ISO, or 

independent entity under the definition 

adopted in this Final Rule. The 

affiliation of a merchant to a 

transmission owner does not establish 

an affiliation between such merchant 

and the RTO, ISO, or independent entity 

transmission provider. 

1684. As to PNM–TNMP’s request 

that the definition of ‘‘affiliate’’ be 

expanded or clarified to encompass 

divisions of an entity that operate as a 

functional unit, we note that PNM–

TNMP’s concern appears to have been 

raised in the context of lifting the price 

cap for capacity reassignment, initially 

proposed only for non–affiliated 

transmission customers. We believe we 

have addressed PNM–TNMP’s concerns 

by lifting the price cap for capacity 

reassignment for all customers, 

including affiliates of the transmission 

provider and the transmission 

provider’s merchant function. 

b. Good Utility Practice 

NOPR Proposal 

1685. In the NOPR, the Commission 

proposed to incorporate the definition 

of reliable operation from FPA section 

215 in the definition of Good Utility 

Practice in the pro forma OATT. 

Comments 

1686. No commenters oppose the 

Commission’s proposal to modify the 

definition of Good Utility Practice to 

reference the reliable operation standard 

of FPA section 215. 

Commission Determination 

1687. The Commission adopts the 

NOPR proposal to incorporate the 

definition of reliable operation from 

FPA section 215 in the definition of 

Good Utility Practice in the pro forma 

OATT. FPA section 215(b) obligates all 

users, owners and operators of the bulk 

power system to comply with reliability 

standards that will take effect under that 

section. Referencing section 215 in the 

definition of Good Utility Practice is 

appropriate to ensure that the reliability 

standards ultimately developed by the 

ERO and approved by the Commission 

are reflected in the pro forma OATT. 

c. Non-Firm Sales 

NOPR Proposal 

1688. The Commission proposed to 

add a definition for Non-Firm Sales to 

clarify the treatment of such sales under 

section 30.4 of the pro forma OATT.962

The Commission proposed defining a 

Non-Firm Sale as ‘‘an energy sale for 

which delivery or receipt of the energy 

may be interrupted for any reason or for 

no reason, without liability on the part 

of either the buyer or seller.’’ The 

Commission also proposed to clarify 

that, for the purposes of applying 


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section 30.4, energy sales that can only 

be interrupted to maintain system 

reliability would be considered firm 

sales. 

Comments 

1689. Several commenters argue that 

the proposed definition of Non-Firm 

Sales could impede a network 

customer’s ability to obtain transmission 

service for certain types of energy 

products. In particular, Duke, EEI, and 

Southern question the treatment of 

power purchase agreements with LD 

provisions under the proposed 

definition. Duke contends that a 

contract with an LD provision might be 

interruptible for any reason, but it 

would still provide for liability in the 

form of LD payments. As a result, the 

LD contract might not fall within the 

definition of a Non-Firm Sale. At the 

same time, network customers can only 

designate resources from system 

purchases not linked to a specific 

generating unit if the purchase power 

agreement is not interruptible for 

economic reasons, does not excuse 

seller performance for economic 

reasons, and requires the network 

customer to pay for the purchase. 

1690. Commenters are thus concerned 

that some contracts with LD provisions 

may be too firm to be a Non-Firm Sale, 

but not firm enough to be designated as 

a network resource. Duke argues that 

network customers should be allowed to 

operate their Network Resources to both 

serve load and sell a firm LD product. 

EEI is concerned that the proposed 

definition of Non-Firm Sales would 

prohibit a network customer from 

making an off-system sale of a firm LD 

product or any other product that does 

not result in undesignation of a Network 

Resource, given the restrictions set forth 

in section 30.4. Duke and EEI therefore 

propose that a Non-Firm Sale should be 

defined as any sale that is not 

sufficiently firm to be designated a 

Network Resource of the purchasing 

entity. Raising concerns similar to those 

raised by Duke and EEI, Southern 

proposes to define Non-Firm Sales as 

any sale that does not commit the 

associated resource to a third party and 

otherwise keeps the resource available 

for network service on a noninterruptible basis. 

1691. NRECA, however, argues that 

contracts with LD provisions are 

typically considered firm products, so 

long as they cannot be curtailed for 

economic reasons alone. NRECA 

requests that the Commission confirm 

its understanding that the mere 

inclusion of an LD provision in a 

contract does not make the sale nonfirm, provided that the sale cannot be 

curtailed only for economic reasons. 

Commission Determination 

1692. The Commission adopts the 

proposed definition of a Non-Firm Sale 

and incorporates that defined term in 

section 30.4 of the pro forma OATT. 

Network customers may use network 

resources for third party sales only if the 

sale is on a non-firm basis. This ensures 

that the network resource is available to 

serve the network load on an 

uninterruptible basis. We conclude that 

it would be inappropriate, as some 

commenters suggest, to relax the 

definition of a Non-Firm Sale to include 

any sale that is not otherwise firm 

enough to be designated as a network 

resource. We address the requirements 

for designation of network resources in 

section V.D.6, concluding that not all 

contracts with LD provisions are 

sufficiently firm to be eligible for 

designation. There we explain that only 

LD provisions that provide for ‘‘make 

whole’’ remedies are sufficiently firm to 

be designated as network resources. It 

does not follow, however, that all 

remaining contracts with LD provisions 

are non-firm. The very existence of an 

LD provision indicates that interruption 

of service will result in liability and, 

thus, such contracts cannot 

automatically be considered Non-Firm 

Sales for purposes of section 30.4. To 

allow otherwise would create 

conflicting incentives for the network 

customer. 

d. Pre-Confirmed Application 

NOPR Proposal 

1693. Incident to the proposal to give 

priority to requests that are preconfirmed, the NOPR proposed a new 

definition of Pre-Confirmed 

Application. 

Comments 

1694. No commenters oppose the 

Commission’s proposed definition of a 

Pre-Confirmed Application. 

Commission Determination 

1695. The Commission adopts the 

proposed definition of Pre-Confirmed 

Application in order to implement the 

reforms adopted above regarding the 

priority of transmission service requests 

under the pro forma OATT. 

e. NOPR Proposals Not Adopted 

Economy Energy 

1696. The Commission also proposed 

in the NOPR to adopt a definition of 

‘‘economy energy’’ incident to its 

proposed changes to section 28.4 

regarding the use of secondary network 

service. As discussed in section V.D.7, 

the Commission retains the existing 

requirement in section 28.4 that permits 

use of secondary network service ‘‘to 

deliver energy to its Network Loads.’’

The proposed definition of ‘‘economy 

energy’’ is therefore unnecessary. 

f. Commenter Proposals 

1697. Several commenters request 

that the Commission amend or add 

other definitions in the pro forma 

OATT. 

(1) Network Transmission Service 

Comments 

1698. TDU Systems and Northwest 

Parties contend that, to help eliminate 

undue discrimination, the Commission 

should modify the definitions of 

‘‘network load’’ and ‘‘network operating 

committee’’ in the pro forma OATT. 

Although the pro forma OATT already 

defines ‘‘network load’’ to include 

wholesale native load, TDU Systems 

contend that transmission providers 

frequently either give preference to their 

own retail native load or ignore 

wholesale customer native load in 

planning and expansion of the system 

and in ATC calculations for processing 

transmission service requests. TDU 

Systems argue that comparable 

treatment of wholesale native load and 

retail native load is required in all 

respects in light of the definition of 

‘‘network load.’’ At the same time, TDU 

Systems argue that the definition of 

‘‘network load’’ unreasonably restricts a 

transmission customer from serving a 

part of its load at a given delivery point 

with non-network resources since it 

provides that a customer ‘‘may not 

designate only part of the load at a 

discrete Point of Delivery.’’

1699. Northwest Parties also assert 

that the Commission should revise the 

definition of ‘‘network load’’ to permit 

point-to-point service and network 

service to the same network load if the 

point-to-point service is ignored in 

calculating load ratio share. Northwest 

Parties also argue that the Commission 

should allow point-to-point and 

network service to the same network 

load if the point-to-point service is 

purchased as non-firm. 

1700. EEI replies in opposition to 

TDU Systems’ proposal to eliminate the 

requirement that a network customer 

may designate only part of its load 

delivery as a network load. EEI argues 

that TDU Systems are incorrect in 

asserting that the definition of ‘‘network 

load’’ prohibits a network customer 

from serving part of its load with nonnetwork resources and secondary 

network service to serve part, or even 


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963See Order No. 888 at 31,736; Order No. 

888–A at 30,259. 

all, of its network load. EEI contends 

that adoption of TDU Systems’ proposal 

would eliminate one of the fundamental 

principles on which network service is 

founded: That the network customer 

must pay for network service based on 

its entire load, including load served by 

behind the meter generation, since the 

transmission provider must plan its 

transmission system to serve the 

customer’s entire load. 

1701. PNM–TNMP agree on reply that 

Commission should reject a change to 

the definition in the pro forma OATT 

regarding network load. PNM-TNMP 

state that the proposal presupposes that 

transmission providers discriminate 

against transmission customers and 

provides preferential treatment to their 

own retail native load in terms of 

planning and expansion of the system 

and in ATC calculations for processing 

transmission service requests. PNM–

TNMP contend that they treat retail 

native load comparably with other 

network customers in all aspects and 

believe that any problems encountered 

by a transmission customer regarding 

undue discrimination should be 

addressed through the enforcement or 

complaint process, and that a change to 

the pro forma OATT is not warranted. 

Commission Determination 

1702. The Commission declines to 

modify the definitions of ‘‘network 

load’’ and ‘‘network operating 

committee.’’ The reforms related to ATC 

calculation and transmission planning 

adopted in this Final Rule adequately 

address the concerns regarding undue 

preference of native load in those areas. 

With regard to the request to allow 

network customers to serve part of their 

load with non-firm point-to-point 

service and part with network service, 

the Commission already determined in 

Order Nos. 888 and 888–A that a 

transmission customer is not allowed to 

take a combination of both network and 

point-to-point transmission service to 

serve the same discrete load.963 We are 

not persuaded to modify that policy 

here. 

(2) Firm and Non-Firm Transmission 

Service 

Comments 

1703. Powerex contends that ‘‘firm 

transmission service’’ is not adequately 

defined or sufficiently described in the 

pro forma OATT to ensure that a 

transmission customer is not being 

required to pay for firm service that is 

curtailed on a regular basis. For 

example, Powerex states the 

Commission could require that firm 

transmission service be available at least 

95 percent of the time (excluding force 

majeure curtailments) in order for 

transmission to be defined as ‘‘firm.’’

1704. Powerex also contends that 

‘‘non-firm transmission service’’ is 

interpreted differently in different 

regions. In the Pacific Northwest, 

Powerex asserts that non-firm service 

implies a lower curtailment priority but 

only as a result of actual transmission 

system constraints (i.e., once the 

operating hour has begun, higher 

priority firm reservations cannot 

implement schedules over lower 

priority non-firm reservation). In 

contrast, Powerex argues that, for some 

transmission providers located in the 

Desert Southwest, transmission capacity 

associated with firm service reservations 

that have capacity schedules attached to 

them (e.g., to deliver operating reserves) 

can also be sold as non-firm service that 

could be interrupted in the operating 

hour by the firm reservation. Powerex 

believes that these two types of service 

could be described as non-firm, noninterruptible (for the Pacific Northwest) 

and non-firm, interruptible (for the 

Desert Southwest). 

Commission Determination 

1705. The Commission finds that the 

clarifications proposed by Powerex are 

unnecessary to remedy undue 

discrimination in the provision of open 

access transmission service. In section 

V.D.8 of this Final Rule, the 

Commission requires transmission 

providers to post additional information 

regarding curtailments in order to 

provide transparency and allow 

customers to determine whether they 

have been treated in the same manner 

as other transmission system users. We 

conclude that existing compliance and 

enforcement procedures, coupled with 

these new posting requirements, are 

sufficient to address improper 

curtailments of service. 

(3) System Impact Study 

Comments 

1706. Powerex urges the Commission 

to modify sections 1.47 and 17.5 of the 

pro forma OATT to clarify that 

transmission providers are not required 

to perform system impact studies for 

short-term service requests. Specifically, 

Powerex requests that the Commission 

amend the definition of a ‘‘system 

impact study’’ to refer only to requests 

for long-term firm point-to-point service 

or network service. Powerex argues that 

short-term firm point-to-point service 

requests do not require transmission 

providers to upgrade their systems and, 

as a result, requiring system impact 

studies for short-term requests often 

creates unnecessary burdens for 

transmission providers by mandating 

them to use limited resources to perform 

studies that do not offer significant 

benefits to customers. Powerex contends 

that the 60-day study period is 

particularly ill-suited for short-term 

transmission requests, most of which 

are for service that must commence 

within the study period. 

Commission Determination 

1707. The Commission declines to 

modify the definition of ‘‘system impact 

study’’ or otherwise modify section 17.5 

to restrict system impact studies only to 

exclude reference to short-term point-topoint service. Regardless of the length of 

a service request, a transmission 

provider must assess whether a system 

impact study is required to evaluate the 

request for transmission service. Only 

upon the completion of such an 

assessment will the transmission 

provider be able to identify the impact 

a particular request will have on the 

grid. We conclude that eliminating or 

shortening the system impact study 

period could jeopardize system 

reliability and therefore reject the 

modifications proposed by Powerex. 

(4) Definitions for RTOs, ISOs and ITCs 

Comments 

1708. Wisconsin Electric and 

International Transmission argue that 

the terms used in the pro forma OATT 

are inadequate when applied to RTO 

regions, especially in MISO. 

International Transmission and 

Wisconsin Electric assert that, in an 

RTO, the transmission provider and 

transmission owner are separate entities 

with separate functions, thus creating a 

need for separate definitions. They also 

contend that additional definitions may 

be needed when the transmission owner 

is an independent stand-alone 

transmission company operating within 

the RTO. 

1709. Wisconsin Electric requests that 

the Commission define the term 

‘‘transmission owner’’ in the pro forma 

OATT and specify which of its 

provisions are applicable to the 

transmission provider and which apply 

to the ‘‘transmission owner.’’

Additionally, Wisconsin Electric states 

that the pro forma OATT includes a 

definition for ‘‘control area’’ and the 

NOPR refers to the geographic area 

served by transmission providers as its 

control area, which in Wisconsin 

Electric’s view is inaccurate in the case 

of MISO. Wisconsin Electric explains 

MISO has shifted to the use of the NERC 


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964Redirect-related issues are addressed in 

section V.D.4. 

965See Order No. 888 at 31,753–54; Order No. 

888–A at 30,304–5; see also Sierra Pacific Power 

Co., 81 FERC ¶ 61,136 at 61,139–40 (1997); New 

England Power Pool, 83 FERC ¶ 61,045 at 61,248 

(1998). 

966See Procedures for Disposition of Contested 

Audit Matters, Order No. 675, 71 FR 9698 (Feb. 27, 

2006), FERC Stats. & Regs. ¶ 31,209 (2006) 

(Contested Audit Matters), order on rehearing and 

clarification, Order No. 675–A, 71 FR 29779 (May 

24, 2006), FERC Stats. & Regs. ¶ 31,217 (2006). 

967E.g., APPA, AWEA, EEI, Morgan Stanley, 

NRG, Southern, TAPS, and Williams. 

968E.g., Ameren, PNM–TNMP, and South 

Carolina E&G. In reply comments, TDU Systems 

urge the Commission to reject this contention. 

functional model and uses terms such as 

‘‘balancing authorities,’’ ‘‘generator 

operators,’’ ‘‘reliability authorities,’’ and 

the like. Wisconsin Electric therefore 

requests that the Commission supplant 

the term ‘‘control area’’ in the pro forma 

OATT with a term that is predicated on 

the performance of a particular function, 

not the type of entity performing the 

function. 

1710. International Transmission does 

not object to the Commission’s proposal 

to largely retain the existing definitions 

set forth in the pro forma OATT, but 

asserts that the Commission should 

explicitly recognize in the Final Rule 

that such definitions may be inadequate 

when applied to RTOs. International 

Transmission also asks the Commission 

not to require RTOs with additional 

definitions in their tariffs to remove 

those definitions when complying with 

the Final Rule and, instead, expressly 

allow RTOs to propose additional 

definitions that may be necessary. 

Commission Determination 

1711. As explained in section IV.C, all 

transmission providers—including ISOs 

and RTOs—will have an opportunity to 

demonstrate that departures from the 

pro forma OATT, as modified by this 

Final Rule, are consistent with or 

superior to the terms and conditions of 

the pro forma OATT. Proposals to 

amend terms such as ‘‘control area’’ or 

‘‘transmission owner’’ based on a 

particular set of facts are best left for 

case-by-case review. 

(5) Other Definitions 

Comments 

1712. Ameren advocates the 

modification of a number of other pro 

forma OATT definitions. Ameren 

proposes definitions for ‘‘source’’ and 

‘‘sink,’’ as well as additional provisions 

in section 22.2 governing source and 

sink of transmission. Ameren also 

requests clarification of the word ‘‘use’’

in section 30.8, arguing that some 

entities have assumed that ‘‘use’’ means 

scheduled amounts. Ameren argues for 

an improved definition of ‘‘transmission 

peak’’ because the data necessary no 

longer resides with the transmission 

owner in an RTO or ISO. Finally, 

Ameren suggests a revised definition of 

‘‘long-term firm,’’ which would include 

only contracts that are longer than one 

year, not just one year or longer, arguing 

it would reduce the number of contracts 

that are only one-year in length that are 

used in the denominator for purposes of 

calculating the load ratio share and for 

ratemaking purposes. On this latter 

point, Ameren asserts that such 

contracts should be reflected as a 

revenue credit instead. In addition, 

Ameren believes that the current 

definition of long-term firm point-topoint service in section 1.18 of the pro 

forma OATT makes calculation of load 

ratio share very difficult in the modern 

RTO/Seams Elimination Cost Allocation 

(SECA) environment. 

Commission Determination 

1713. The Commission is not 

persuaded to adopt the revisions 

proposed by Ameren. We believe that 

what constitutes source and sink is 

sufficiently addressed in Order No. 888 

and OASIS related proceedings and we 

will not expand the discussion here.964

Order No. 888 also made clear that there 

are no ‘‘load ratio’’ limitations on the 

use of interfaces under section 30.8 of 

the pro forma OATT.965 Otherwise, 

requests for interface capacity are 

subject to the pro forma OATT 

procedures. Moreover, Ameren has 

failed to justify revising the definition of 

‘‘transmission peak.’’ While peak load 

data ultimately resides with the RTO or 

ISO, each transmission provider 

coordinates this type of data with RTO 

or ISO. Finally, we reaffirm that longterm firm service is service with a term 

of one year or more. Modifying the term 

of long-term service to reduce the 

number of contracts used in the 

denominator for purposes of calculating 

the load ratio share and for ratemaking 

purposes may affect how the 

transmission provider plans its system 

to service customers and has not been 

justified. 

E. Enforcement 

1714. The Commission attaches 

substantial importance to strengthening 

compliance with the OATT, on 

monitoring and auditing OATT 

compliance, including its staff’s efforts 

to resolve disputes about compliance 

through the Enforcement Hotline and 

other dispute resolution mechanisms, 

and on investigating potential and 

alleged OATT violations. The expansion 

of the Commission’s enforcement 

powers pursuant to EPAct 2005 directly 

augmented its ability to enforce the 

OATT by, among other things, 

providing authority to assess civil 

penalties of up to $1 million for each 

day that an OATT violation continues. 

The Commission intends to use its 

enforcement powers with respect to the 

OATT in a fair and even-handed 

manner, pursuant to the principles set 

forth in the Policy Statement on 

Enforcement. 

1. General Policy 

a. Compliance Review Regime 

NOPR Proposal 

1715. The Commission proposed to 

maintain a strong program to audit 

compliance with the new pro forma 

OATT. The audit program would 

include operational audits similar to 

past OATT compliance audits, during 

which staff may collect information on 

implementation of a transmission 

provider’s OATT. The Commission 

stated that it would issue public reports 

of audit results and noted that contested 

audits would be subject to the 

Commission’s Final Rule on contested 

operational audits.966

Comments 

1716. Most initial commenters 

support a strong staff audit program.967

Other commenters counter that staff 

audits will not be needed if the 

Commission issues a corrected pro 

forma OATT, especially with respect to 

RTOs and ISOs.968 These commenters 

argue that formal complaints, 

Enforcement Hotline calls and random 

audits sufficiently inform staff of OATT 

compliance issues as to make additional 

staff audits unnecessary. Southern 

asserts that, under the separation of 

function policy, Commission audit staff 

should be separated from investigative 

and enforcement staff. Particular 

commenters contend that the 

Commission should focus compliance 

efforts on specific OATT provisions, 

such as those concerning network 

service (Arkansas Cities), or on 

structural issues such as independent 

planning and operation of transmission 

facilities (Reliant). Nevada Companies 

suggests that the Commission set up 

regional audit teams to foster strong 

working relationships with transmission 

providers. EPSA asks the Commission to 

adopt stronger measures than a staff 

audit program to monitor compliance. 

EPSA’s proposed measures include 

requiring transmission providers to: 

designate compliance officers to report 

OATT violations to company boards; 

undergo compliance audits by an 


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969See, e.g., Duke Power, 113 FERC ¶ 61,288 

(2005); MidAmerican Energy Holdings Co., 113 

FERC ¶ 61,298 (2005). 

970 18 CFR 385.2202. 

971Statement of Administrative Policy on 

Separation of Functions, 101 FERC ¶ 61,340 at P 

24–26 (2002). 

972See also Order No. 675–A at P 25–29 (the 

Commission’s regulation and policy statement on 

separation of functions remain applicable following 

EPAct 2005, and efficiency and sound 

administrative practice continue to favor the 

sharing of information between the Commission’s 

audit staff and investigative staff). 

973E.g., Alberta Intervenors, Arkansas 

Commission, Constellation, EEI, EPSA, MISO/PJM 

States, Nevada Companies, PNM–TNMP, South 

Carolina E&G, Southwestern Coop, and Suez Energy 

NA. 

independent auditor in response to 

material violations; and hire an 

independent administrator to oversee 

OATT compliance and regional 

planning efforts if a transmission 

provider has not complied with its new 

OATT within a specified period of time. 

In reply comments, MISO opposes 

EPSA’s proposal for a third-party 

compliance administrator for RTOs and 

ISOs if they do not timely comply with 

new OATT provisions, arguing that 

these entities already are independent 

administrators of transmission grids and 

planning processes. MISO asserts that 

inserting an ‘‘independent’’ authority 

over OATT compliance by RTOs and 

ISO would create a superfluous 

bureaucratic layer. NRECA opposes 

EPSA’s proposal because a third-party 

compliance administrator or auditor 

would be too expensive and the 

Commission cannot delegate its 

compliance authority. 

1717. Noting that the Commission 

required RTOs to undertake extensive 

market monitoring in Order No. 2000, 

PJM states that the Commission should 

require in the pro forma OATT a similar 

degree of market monitoring in nonRTO areas to make available to 

Commission staff information needed to 

ascertain market abuses in these areas. 

PJM asserts that any such market 

monitoring should be performed by 

entities independent of the non-RTO 

utilities, with Commission oversight. 

Indicated Parties reply that RTOs’

market monitors should examine market 

power in transmission planning because 

RTOs delegate transmission operations 

and planning duties to constituent 

transmission owners that retain 

incentives to benefit affiliates or 

vertically-integrated divisions. 

Commission Determination 

1718. The Commission adopts the 

NOPR proposal to emphasize a strong 

staff audit program for compliance with 

OATT requirements, including 

operational audits. Staff audits of OATT 

compliance may be random or targeted 

with respect to the entities being 

audited or particular provisions of the 

OATT that are scrutinized. Because its 

responsibility is to assess and ensure 

compliance with the OATT, staff will 

maintain discretion as to the entities it 

audits and the subject matter of these 

audits. The Commission encourages 

transmission providers to designate 

employees as compliance officers for the 

OATT or to conduct third-party audits 

relating to OATT compliance when 

appropriate. However, we do not believe 

that staff should forego an audit of an 

entity’s OATT compliance solely 

because a transmission provider has 

designated an OATT compliance officer, 

engaged a third-party auditor, or 

transferred transmission functions to an 

independent transmission coordinator. 

We decline EPSA’s proposal to require 

such actions, except on a case-by-case 

basis when warranted. 

1719. We disagree with PJM’s request 

that the Commission require third-party 

market monitoring to ascertain market 

abuses occurring with respect to 

transmission providers outside RTOs 

and ISOs, subject to Commission 

oversight. In a number of instances 

since 2000, the Commission has 

established third-party monitoring of a 

transmission provider located outside 

an RTO or ISO.969 These monitors were 

established on a case-specific basis to 

address concerns related to the 

transmission provider at issue. We have 

no evidence to support requiring 

monitors for every transmission 

provider in the Nation. Further, the 

Commission has access to substantial 

information on OATT compliance by 

transmission providers that are not 

RTOs or ISOs through their postings on 

OASIS, informal and formal complaints 

by customers, and reports by market 

monitors for such transmission 

providers. Indeed, the revised pro forma 

OATT will greatly enhance our 

oversight and enforcement capabilities 

by increasing the transparency of many 

critical functions under the pro forma 

OATT, such as ATC calculation and 

transmission planning. PJM has not 

provided any evidence that the 

enhanced transparency under the 

OATT, coupled with the Commission’s 

own monitoring and audits of OATT 

compliance and its enhanced 

enforcement authority, will be 

insufficient to ascertain and deter OATT 

violations. We do not object to the 

suggestion of Indicated Parties that RTO 

and ISO market monitors examine 

market power in transmission planning, 

so long as the market monitors’

activities in this respect are consistent 

with these roles as set forth in the 

applicable RTO and ISO tariffs. 

1720. We do not agree with 

Southern’s assertion that the 

Commission’s audit staff should be 

separated from its investigative and 

enforcement staff. The Commission’s 

separation of functions regulation 970

generally permits Commission auditors, 

investigators and enforcement staff to 

speak freely to persons inside the 

Commission as to the subject matter of 

their inquiries.971 Southern has not 

cited any justification for restricting 

communications among these staff 

members or from them to the 

Commission. To the contrary, a free 

flow of communications among auditors 

and investigators, consistent with the 

Commission’s rule on staff separation of 

functions, should increase the efficiency 

of the Commission staff’s compliance 

program and enforcement efforts.972

b. Use of Independent Third Party 

Audits 

NOPR Proposal 

1721. The Commission proposed not 

to mandate the use of third party 

auditors and, instead, proposed that 

Commission staff conduct audits of 

compliance with the pro forma OATT. 

The Commission stated that it may 

require third party compliance audits as 

part of a compliance plan following a 

Commission staff audit report. In 

response to situations such as 

systematic OATT violations, a pattern of 

repeated violations, or violations that 

require ongoing monitoring, the 

Commission could require an audited 

party to hire a third party to continue 

compliance audits. 

Comments 

1722. Most initial commenters agree 

with the Commission’s proposal to 

require third-party audits only as part of 

an individual post-audit compliance 

plan.973 EEI and Southwestern Coop 

submit that selection of third-party 

auditors should be subject to 

Commission review and approval, while 

South Carolina E&G cautions that the 

Commission should carefully weigh the 

costs and benefits of independent 

auditors before requiring their use. 

Southern suggests that third-party 

audits be required only for systematic, 

egregious OATT violations. Entegra 

doubts that third-party auditors can 

remedy patterns of discrimination by 

transmission providers against 

independent merchant generators. 


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974Prohibition of Energy Market Manipulation, III 

FERC Stats. & Regs. ¶ 31,202 (2006), order denying 

rehearing, 114 FERC ¶ 61,300 (2006). 

975NOPR at P 384. 

976E.g., APPA, EEI, EPSA, Nevada Companies, 

PNM–TNMP, Southern, and Southwestern Coop. 

Southwestern Coop also urges speedy review of 

violations and swift assessment of penalties. In 

reply comments, Sacramento adds that the 

Commission may assess civil penalties against a 

transmission provider that engages in unduly 

discriminatory behavior in its transmission 

planning process. 

977E.g., Arkansas Commission and ELCON. 

978Wisconsin Electric asserts that the 

Commission has recognized this principle in other 

contexts, citing Financial Reporting and Cost 

Accounting, Oversight and Recovery Practices for 

Regional Transmission Organizations and 

Independent System Operators, FERC Stats. & Regs. 

¶ 35,546 at P 9 (2004). 

979E.g., Nevada Companies and PNM–TNMP. 

980EEI observes that the Commission held in its 

final rule on contested audit procedures that ‘‘an 

audited person who appropriately interposes the 

attorney-client privilege will not be considered noncooperative.’’ Contested Audit Matters at P 35. 

981 16 U.S.C. 824q(k). 

982Policy Statement on Enforcement at P 1. 

983 Id. at P 13. 

Commission Determination 

1723. The Commission adopts the 

NOPR proposal not to require generally 

the use of third party auditors to assess 

compliance with the OATT. We believe 

that a requirement for the use of thirdparty audits in compliance plans should 

depend on particular facts, including 

the egregiousness and extent of 

violations found during a staff audit or 

investigation and the appropriate scope 

or cost of a third-party audit. As stated 

above, we encourage transmission 

providers to use third-party compliance 

audits when appropriate to supplement 

our staff’s audit efforts. 

2. Civil Penalties 

1724. In the NOI, the Commission 

asked for comment as to whether it 

should address imposing remedies or 

penalties against transmission providers 

as part of OATT reform. After the NOI, 

the Commission issued its Policy 

Statement on Enforcement and, in 

response to specific authority granted it 

in EPAct 2005, issued Order No. 670, 

the Anti-manipulation Rule. 974

a. Whether Civil Penalties Should Be 

Specified in the OATT 

NOPR Proposal 

1725. Aside from operational 

penalties proposed in the NOPR, 975 the 

Commission proposed not to establish a 

schedule of enforcement remedies and 

sanctions in the pro forma OATT. 

Rather, the Commission stated that it 

would address OATT violations and 

appropriate responses on a case-by-case 

basis, consistent with the Policy 

Statement on Enforcement. The 

Commission explained that it may 

impose civil penalties when warranted, 

after consideration of applicable factors 

listed in the Policy Statement on 

Enforcement; OATT violators also will 

be expected to disgorge unjust profits 

when they can be determined or 

reasonably estimated. 

Comments 

1726. The majority of parties filing 

comments on this issue agree that the 

Commission should assess civil 

penalties on a case-by-case basis under 

the guidance of the Policy Statement on 

Enforcement. 976 Other commenters 

instead support incorporation in the pro 

forma OATT of a schedule of significant 

remedies and sanctions for specific 

violations to assure transparency and 

certainty as to situations in which 

penalties would be assessed and to deter 

anticompetitive behavior. 977 EPSA 

advises that the Commission refrain 

from setting pre-determined limits on 

penalty amounts because each violation 

of a specific pro forma OATT provision 

may present different facts that may 

warrant different outcomes. Nevada 

Companies suggest that the Commission 

provide incentives to construct new 

transmission infrastructure rather than 

implement an overbearing penalty 

regime because additional transmission 

capacity itself will resolve many 

complaints. 

1727. Wisconsin Electric concludes 

that OATT violations by non-profit 

RTOs and ISOs should not be subject to 

civil penalties because they would be 

passed through to customers and not act 

as an effective deterrent. 978 Rather than 

assess a penalty in response to an RTO’s 

or ISO’s OATT violation, Wisconsin 

Electric suggests that the Commission 

could intensify oversight of an RTO’s or 

ISO’s OATT compliance. NorthWestern 

comments, in contrast, that RTOs and 

ISOs should not be exempted from civil 

penalty assessments for their OATT 

violations, because these violations 

could have as much or more adverse 

effects on transmission access or system 

reliability as would OATT violations by 

other transmission providers. 

1728. Several commenters support the 

Commission’s proposal to consider 

mitigating factors listed in the Policy 

Statement on Enforcement in assessing 

civil penalties for OATT violations. 979

In this regard, EEI states that the 

Commission should clarify that when a 

party engages in self-reporting, 

compliance programs or cooperation 

with Commission staff, the Commission 

will recognize the party’s attorney-client 

privilege. 980

1729. EEI suggests that the 

Commission establish ‘‘safe harbors’’

against civil penalties for OATT 

violations involving reasonable 

interpretations of tariff provisions or for 

actions taken for reliability purposes 

that are consistent with good utility 

practice. PNM–TNMP and Southern ask 

the Commission to clarify that LSEs will 

not be penalized for OATT violations 

for taking actions necessary to meet 

their native load obligations since, 

pursuant to new FPA section 217, 981

LSEs should not be considered to have 

engaged in ‘‘undue discrimination or 

preference’’ for certain actions required 

to serve native load customers. TDU 

Systems argue in reply comments that a 

‘‘safe harbor’’ approach could permit 

unduly discriminatory or preferential 

behavior that would be penalized under 

a case-by-case approach. Entegra replies 

that safe harbors for ‘‘reasonable’’ tariff 

interpretations would give verticallyintegrated utilities license to 

discriminate against competitors, and 

suggests that the Commission ensure 

that the OATT operates as a sword for 

attacking undue discrimination, not as a 

shield for defending it. Occidental 

replies that transmission providers with 

a Commission-approved independent 

transmission coordinator should not be 

insulated from tariff-based civil 

penalties and other sanctions. 

Commission Determination 

1730. Following enactment in EPAct 

2005 of enhanced authority for the 

Commission to assess civil penalties for 

violations of statutes it administers and 

of regulations and orders under these 

statutes, the Commission issued the 

Policy Statement on Enforcement to set 

forth how it intends to use this authority 

consistent with the statute. 982

Underlying this policy is the recognition 

that the appropriate basis for assessment 

of a civil penalty for a violation is an 

examination of the facts and 

circumstances relating to that violation, 

and the use of discretion and flexibility 

to address it on its merits. This 

examination includes a review of all 

applicable mitigating factors set forth in 

the Policy Statement on Enforcement. 

While we understand that establishing a 

schedule of civil penalties for violations 

of particular provisions of the pro forma 

OATT would establish greater 

specificity with respect to civil 

penalties, the Commission already 

concluded in the Policy Statement on 

Enforcement that it would ‘‘not 

prescribe specific penalties or develop 

formulas for different violations.’’ 983

We see no justification to depart from 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12487 

984We have also provided clarification on the 

procedures that would apply to the assessment in 

formal proceedings of civil penalties relating to 

OATT violations in our recent Statement of 

Administrative Policy Regarding the Process for 

Assessing Civil Penalties, 117 FERC ¶ 61,317 (2006). 

985Rules Concerning Certification of the Electric 

Reliability Organization; and Procedures for the 

Establishment, Approval, and Enforcement of 

Electric Reliability Standards, Order No. 672, 71 FR 

8662 (Feb. 17, 2006), FERC Stats. & Regs. ¶ 31,204 

at P 634 (2006), order on reh’g, Order No. 672–A, 

FERC Stats. & Regs. ¶ 31,212 (2006). 

986Policy Statement on Enforcement at P 20. Cf. 

Order No. 672–A at P 56–57 (holding that for 

determining a penalty pursuant to the FPA section 

215 reliability program, circumstances such as 

organization structure or non-for-profit status will 

be considered, but that there should not be an 

automatic exemption from monetary penalties for 

RTOs and ISOs). 

987Citing Contested Audit Matters at P 35. 

988Policy Statement on Enforcement at P 26. 

989See In re PacifiCorp, 118 FERC ¶ 61,026 at P 

3, 8 and attached stipulation and consent agreement 

at P 24 (2007) (referring to transmission provider’s 

waivers of attorney-client privilege as an element in 

making finding of exemplary cooperation with 

investigation when approving settlement assessing 

civil penalty that resolved a transmission provider’s 

violations of its OATT, among other matters); In re 

Entergy Services, Inc., 118 FERC ¶ 61,027 at P 15, 

18 (2007) (same). 

990E.g., EEI, ELCON, Morgan Stanley, Nevada 

Companies, Northwest IOUs, Progress Energy, 

PNM–TNMP, Sempra Global, Southern, and TDU 

Systems. 

991E.g., EEI, Nevada Companies, Northwest IOUs, 

Progress Energy, PNM–TNMP, Sempra Global, and 

Southern. 

992E.g., APPA. 

that decision with respect to violations 

of OATT provisions. 

1731. Several commenters ask that we 

establish specific ‘‘safe harbors’’ or 

exemptions from assessment of civil 

penalties for OATT violations in 

specific circumstances or with respect 

to specific types of entities that may 

engage in OATT violations. We decline 

to create automatic safe harbors for 

specific circumstances or specific types 

of OATT violations. The creation of 

such exemptions would require us to 

forego the examination of the specific 

circumstances of particular violations 

that we described in the Policy 

Statement on Enforcement as the 

touchstone of our policy in assessing 

civil penalties. Instead, we will decide 

requests for leniency in particular cases 

by using the principles set forth in the 

Policy Statement on Enforcement and 

considering all applicable mitigating 

factors listed therein.984

1732. Likewise, we will not establish 

an automatic exemption from civil 

penalty assessments for OATT 

violations committed by particular types 

of entities such as non-profit RTOs and 

ISOs. The Commission decided last year 

that it would not automatically exempt 

RTOs and ISOs from penalties assessed 

by the Electric Reliability Organization 

or Regional Entities for reliability 

violations pursuant to new FPA section 

215. In Order No. 672, the Commission 

stated, ‘‘[w]hile we recognize that RTOs 

and ISOs have some unique 

characteristics, we do not believe that a 

generic exemption from any type of 

penalty is appropriate for any entity, 

including an RTO or ISO.’’ 985 We 

believe the same principle applies to 

civil penalties for OATT violations. 

However, in assessing civil penalties for 

OATT violations, we will consider all 

applicable facts relating to the violator, 

including the effect of potential 

penalties on the financial viability of the 

violator.986

1733. We agree with commenters who 

state that the Commission and its staff 

should recognize the valid assertion of 

the attorney-client privilege in the 

context of investigations, audits and 

other fact-finding activities. As EEI 

points out, we recently stated with 

respect to audits that we would not 

consider an entity to be uncooperative 

with audit staff if the entity 

appropriately asserts that a 

communication or document is covered 

by that privilege.987 We take the same 

position with respect to investigations 

or other fact-finding undertakings with 

respect to possible OATT violations. 

1734. In the Policy Statement on 

Enforcement, however, the Commission 

drew a distinction between cooperation, 

which we expect from entities subject to 

the Commission’s jurisdiction given 

their statutory obligation to provide 

information to us, and ‘‘exemplary’’

cooperation, which ‘‘quickly ends 

wrongful conduct, determines the facts, 

and corrects a problem.’’ 988 The 

Commission explained that we will give 

some consideration to exemplary 

cooperation and indicated that one 

example of such cooperation is a 

situation in which an entity being 

investigated provides to staff internal 

investigations or audit reports relating 

to misconduct. These investigations and 

reports may include information that an 

entity could properly shield from 

disclosure pursuant to the attorneyclient privilege. We observe that an 

entity that is in a position to assert this 

privilege validly also has the option to 

waive it. If a waiver of attorney-client 

privilege, whether related to an internal 

investigation or audit or not, assists staff 

in ascertaining the facts relating to 

alleged or apparent misconduct, ends 

misconduct quickly or otherwise 

substantially advances an investigation 

or inquiry, that waiver may be an 

element in finding ‘‘exemplary 

cooperation’’ as described in the Policy 

Statement on Enforcement.989

b. Whether Transmission Providers 

Should Be Subject to Revocation of 

Market-Based Rates for OATT 

Violations 

NOPR Proposal 

1735. The Commission observed in 

the NOPR that some OATT violations, 

after applying the factors in the Policy 

Statement on Enforcement to all facts 

and circumstances, may merit 

revocation of market-based rate 

authority. Before considering revoking 

an entity’s market-based rate authority 

for an OATT violation, the Commission 

proposed that it must find a nexus 

between the specific facts relating to the 

OATT violation and the entity’s marketbased rate authority. The Commission 

also proposed that if it determines, as a 

result of a significant OATT violation, to 

revoke the market-based rate authority 

of a transmission provider within a 

particular market, each affiliate of the 

transmission provider that possesses 

market-based rate authority would have 

that authority revoked in that market, 

effective on the date of revocation of the 

transmission provider’s market-based 

rate authority. 

Comments 

1736. Most parties that submitted 

initial comments on this issue support 

the Commission’s conclusion that, in 

certain circumstances, it may be 

appropriate to revoke the market-based 

rate authority of an entity that engages 

in an OATT violation.990 The majority 

of these commenters support the 

Commission’s proposal to do so only if 

it finds a nexus between the OATT 

violation and the entity’s market-based 

rate authority.991

1737. Some commenters oppose the 

requirement for a nexus between the 

OATT violation and the entity’s marketbased rate authority because the 

Commission has not stated what facts 

would be sufficient to show such a 

nexus.992 EPSA and NRECA (in reply 

comments) contend that if the 

Commission does not remove the 

‘‘nexus’’ condition, it should clarify 

what constitutes a ‘‘nexus’’ between an 

OATT violation and an entity’s marketbased rate authority. Similarly, PNM–

TNMP argues that such a nexus must be 

clear and fact-specific, consistent with 

the Policy Statement on Enforcement. 

TDU Systems contend in reply 


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12488 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

993E.g., APPA, EPSA, and TAPS. 

994E.g., EEI, Nevada Companies, Northwest IOUs, 

Progress Energy, PNM–TNMP, Sempra Global, and 

Southern. 

comments that, at a minimum, a 

transmission provider or its affiliate that 

has market-based rate authority must 

overcome a rebuttable presumption that 

its OATT violation has the requisite 

‘‘nexus’’ to support revocation of such 

authority. 

1738. Other commenters argue that a 

serious OATT violation removes the 

mitigation of transmission market power 

provided by adherence to an OATT, 

thereby eviscerating one of the essential 

requirements for market-based rate 

authority.993 EEI and PNM–TNMP reply 

that not every OATT violation 

diminishes the availability of 

transmission service so as to establish 

vertical market power. 

1739. APPA and TDU Systems suggest 

in reply comments that the proposed 

nexus condition would unduly limit 

any sanctions, because the shareholders 

of the violator could still reap the 

benefits of such a violation if an affiliate 

that did not have any knowledge of the 

OATT violation could continue to 

engage in transactions under marketbased rate authority. According to 

APPA, this possibility could lessen the 

incentive for senior management over a 

transmission provider and affiliates to 

make OATT compliance a high priority. 

As such, APPA and TAPS suggest that 

the Commission consider revoking a 

transmission provider’s market-based 

rate authority for a ‘‘material’’ OATT 

violation that effectively denies, delays, 

or diminishes a customer’s access to 

transmission service essential to 

mitigating transmission market power. 

1740. TDU Systems caution that 

revocation of market-based rate 

authority may not be sufficient to deter 

OATT violations if reversion to costbased rates may provide a transmission 

provider with the ability to recover all 

costs and receive higher revenues than 

competitive markets might otherwise 

produce. Therefore, TDU Systems ask 

that the Commission consider 

assessment of civil penalties in addition 

to revocation of market-based rate 

authority. 

1741. The majority of commenters 

disagree, however, with the 

Commission’s proposal to revoke the 

market-based rate authority of all 

affiliates of a transmission provider to 

the same extent that we revoke that 

transmission provider’s market-based 

rate authority.994 These commenters 

assert that affiliates that have no 

knowledge of, or involvement in, their 

affiliated transmission provider’s 

unlawful activities should not lose their 

market-based rate authority as a result of 

the transmission provider’s OATT 

violation. NRECA replies that marketbased rate authority is a privilege, not a 

right, and asserts that the Commission 

should revoke market-based rate 

authority in response to an OATT 

violation that indicates that a public 

utility possesses market power. 

1742. APPA also suggests that, short 

of revocation of a transmission 

provider’s market-based rate authority 

in response to an OATT violation, the 

Commission could condition that 

authority, or the market-based rate 

authority of the transmission provider’s 

affiliates. APPA provides the following 

examples of such conditions: A 

requirement to participate in joint 

planning of transmission facilities with 

the transmission provider’s network 

customers and offer these customers 

appropriate credits under OATT section 

30.9; an offer of joint transmission 

ownership opportunities to LSEs for 

new transmission facilities on 

reasonable terms and conditions; and an 

offer to network service customers to 

participate in the ownership of the 

transmission provider’s existing 

transmission system on a load ratio 

share basis. 

Commission Determination 

1743. We adopt the NOPR proposal to 

revoke an entity’s market-based rate 

authority in response to an OATT 

violation only upon a finding of a 

specific factual nexus between the 

violation and the entity’s market-based 

rate authority. We believe that the 

‘‘nexus condition’’ is required in order 

to ensure that our actions are not 

arbitrary or capricious or based on an 

inadequate factual record. We note that 

in this context the Commission has the 

burden to show a factual nexus. We do 

not assign a burden on the violator to 

show the lack of this nexus. 

1744. Determining what would be a 

sufficient factual nexus between an 

OATT violation and revocation of the 

violator’s market-based rate authority is 

best left to a case-by-case consideration. 

The wide range of positions among 

commenters on how to define a 

sufficient factual nexus itself suggests 

that this finding is best made after 

review of a specific factual situation. 

Some commenters assert that a finding 

of a ‘‘serious’’ or ‘‘material’’ violation of 

the OATT would be sufficient. We 

disagree. While an entity’s 

inconsequential OATT violation would 

not serve as a basis for revoking that 

entity’s market-based rate authority, our 

view is that the nexus condition 

requires us to find both that a 

substantial OATT violation has 

occurred and that the violation either 

related to the exercise of the violator’s 

market-based rate authority or violated 

a specific condition of that authority. 

1745. The Commission emphasizes 

that we have discretion to fashion 

remedies for OATT violations that relate 

to the violator’s market-based rate 

authority in instances in which we do 

not find a factual nexus justifying 

revocation of that authority. For 

example, in appropriate circumstances, 

we may modify or add additional 

conditions to the violator’s marketbased rate authority or impose other 

requirements to help ensure that the 

violator does not commit future, similar 

misconduct. Nor is revocation of 

market-based rate authority the only 

action we may take to respond to an 

OATT violation that meets the nexus 

condition. We will consider whether to 

impose sanctions such as assessment of 

civil penalties for particularly serious 

OATT violations in addition to 

revocation of the violator’s market-based 

rate authority. 

1746. We do not adopt our proposal 

from the NOPR to revoke the marketbased rate authority of each affiliate of 

a transmission provider that loses its 

market-based rate authority within a 

particular market as a result of an OATT 

violation. Rather, we will create a 

rebuttable presumption that all affiliates 

of a transmission provider should lose 

their market-based rate authority in each 

market in which their affiliated 

transmission provider loses its marketbased rate authority as a result of an 

OATT violation. We will allow an 

affiliate of a transmission provider to 

retain its market-based rate authority in 

a market area if the affiliate overcomes 

the rebuttable presumption with respect 

to that market area. 

1747. We expect that the issue of 

potential revocation of market-based 

rate authority will arise as a result of an 

OATT violation in a market in which 

the transmission provider possesses 

transmission market power through the 

ownership of transmission facilities in 

that market. For these markets, we have 

evaluated whether a transmission 

provider should receive authority to 

make sales of electric power for resale 

at market-based rates using a four-prong 

analysis. In this analysis we consider 

whether the transmission provider and 

its affiliates have adequately mitigated 

market power in generation and 

transmission, whether the transmission 

provider or its affiliates can erect other 

barriers to entry, and whether there is 

evidence that the transmission provider 

and its affiliates have engaged in 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12489 

995 In our recent NOPR on market-based rates for 

wholesale sales of electricity, the Commission 

proposed to discontinue referring to affiliate abuse 

among a transmission provider and its affiliates as 

a separate ‘‘prong’’ of our analysis of whether to 

grant market-base rate authority. The Commission 

instead proposed to address affiliate abuse by 

requiring that transmission providers and their 

affiliates comply with restrictions and conditions 

set forth in the regulations we propose in that 

proceeding. Market-Based Rates for Wholesale 

Sales of Electric Energy, Capacity and Ancillary 

Services by Public Utilities, 71 FR 33102 (Jun. 7, 

2006), FERC Stats. & Regs. ¶ 32,602 at P 13 (2006). 

996We observe that specific situations in which 

transmission providers have agreed to resolve staff 

allegations that they engaged in OATT violations 

have involved transactions with affiliates. See 

Idaho Power (settlement of, among other issues, an 

Enforcement staff allegation that a transmission 

provider permitted its merchant function to request 

non-firm transmission to enable the merchant 

function to make off-system sales that by definition 

were not used to serve native load, so that the 

transmission did not qualify for the ‘‘native load’’

priority specified in section 28.4 of the transmission 

provider’s OATT); Cleco Corp., 104 FERC ¶ 61,125 

(2003) (settlement between Enforcement staff and a 

utility holding company and its subsidiaries 

relating, in part, to the provision by a transmission 

provider of a unique type of transmission service 

that was neither made available to non-affiliates nor 

included in its FERC tariff); Tucson Electric Power 

Co., 109 FERC ¶ 61,272 (2004) (operational audit in 

which staff found that, among other matters, a 

transmission provider permitted its wholesale 

merchant function to purchase hourly non-firm and 

monthly firm point-to-point transmission service 

using an off-OASIS scheduling procedure while the 

transmission provider did not post on its OASIS the 

availability of capacity on these paths); South 

Carolina Electric & Gas Co., 111 FERC ¶ 61,217 

(2005) (settlement of Enforcement staff allegation 

that a transmission provider made available firm 

point-to-point transmission service to its affiliated 

merchant function that did not submit transmission 

schedules with specific receipt points for the 

service as required by section 13.8 of the 

transmission provider’s OATT); and MidAmerican 

Energy Co., 112 FERC ¶ 61,346 (2005) (operational 

audit in which staff found, among other things, that 

a transmission provider permitted its wholesale 

merchant function to (a) use network transmission 

service to bring short-term energy purchases onto 

its system while it simultaneously made off-system 

sales, inconsistently with the preamble to Part III 

of the transmission provider’s OATT and section 

28.6 of its OATT; and (b) confirm firm network 

transmission service requests without identifying a 

designated network resource or acquiring an 

associated network resource, in some instances 

using this service to deliver short-term energy 

purchases used to facilitate off-system sales, 

inconsistent with section 29.2 or section 30.6 of the 

transmission provider’s OATT). See also 

Commission orders cited in note 989 supra. 

997APPA, Nevada Companies, PNM–TNMP, 

Southwestern Coop, and TDU Systems. 

998Similarly, in issuing the Anti-manipulation 

Rule, we declined to provide specific examples of 

what would constitute market manipulation. Order 

No. 670 at P 64–67. 

999 5 CFR 1320.11. 

1000 44 U.S.C. 3507(d). 

affiliate abuse or reciprocal dealing.995

In particular, we have long held that the 

existence of an OATT is deemed to 

mitigate vertical market power and 

transmission market power held by a 

transmission provider and its affiliates 

in a particular market. An OATT 

violation by a transmission provider in 

a market in which it possesses 

transmission market power that merits 

revocation of the transmission 

provider’s market-based rate authority 

may call into question whether the 

transmission provider’s affiliates 

continue to qualify for market-based 

rates in that market under the standards 

that we have established.996 As a result, 

we believe that it is appropriate to 

establish a presumption in this 

circumstance that if we find that a 

transmission provider should lose its 

market-based rate authority in a market 

in which it possesses transmission 

market power, we will revoke the 

market-based rate authority in that 

market of all affiliates of the 

transmission provider. 

1748. We are mindful, however, that 

the circumstances of a particular 

affiliate may not always justify the 

imposition of a remedy so severe as 

revocation of market-based rate 

authority in a particular market when its 

affiliated transmission provider loses its 

market-based rate authority in that 

market as a result of an OATT violation. 

To afford due process to a transmission 

provider’s affiliates in that situation, 

and to ensure that a determination to 

revoke market-based rate authority in a 

particular market for a transmission 

provider and all of its affiliates that 

possess such authority is adequately 

based upon record evidence and not 

arbitrary or capricious, we will allow an 

opportunity for each such affiliate to 

make a showing that it should retain its 

market-based rate authority or that 

enforcement action against it should be 

less severe than revocation. The 

determination whether an affiliate has 

overcome the rebuttable presumption 

depends on an analysis of specific facts 

in the record. Relevant facts would 

include, but are not limited to, whether: 

(1) The transmission provider and the 

affiliate were under the same control; (2) 

the affiliate knew of, participated in or 

was an accomplice to the OATT 

violation; (3) the affiliate assisted the 

transmission provider in exercising 

market power; or (4) the affiliate 

benefited from the violation. 

c. Whether Certain OATT Violations 

Should Be Considered Market 

Manipulation Under Section 222 of the 

FPA 

NOPR Proposal 

1749. The Commission proposed in 

the NOPR to decline to identify in the 

pro forma OATT specific conduct that 

constitutes per se market manipulation. 

The Commission proposed to consider 

on a case-by-case basis, if and when 

they arise, whether specific 

circumstances relating to OATT 

violations constitute market 

manipulation under the standards set 

forth in Order No. 670. 

Comments 

1750. All commenters on this issue 

concur with a case-by-case approach to 

it.997 Southwestern Coop suggests that, 

as the Commission gains sufficient 

experience to describe particular 

misconduct as market manipulation per 

se, it should identify such misconduct 

in the OATT. While contending that the 

Commission should act with caution in 

listing behaviors that constitute per se 

market manipulation in view of the 

dynamic nature of markets, TDU 

Systems urge the Commission to specify 

in the OATT that transmission planning 

misconduct could constitute a form of 

market manipulation or abuse. 

Commission Determination 

1751. We adopt the NOPR proposal 

for a case-by case approach to 

considering whether OATT violations 

may constitute market manipulation. 

Without reference to a specific factual 

pattern developed in an investigation or 

on-the-record proceeding, the 

Commission is not in a position to 

identify market manipulation relating to 

OATT violations.998

VI. Information Collection Statement 

1752. The Office of Management and 

Budget (OMB) regulations require that 

OMB approve certain reporting, record 

keeping, and public disclosure 

(collections of information) imposed by 

an agency.999 Pursuant to OMB 

regulations, the Commission is 

providing notice of its proposed 

information collections to OMB for 

review under section 3507(d) of the 

Paperwork Reduction Act of 1995.1000

1753. The Commission identifies the 

information provided under Part 35 

subpart C as contained in FERC–516 

and Part 37 as contained in FERC–717. 

The Commission solicited comments on 

the need for this information, whether 

the information will have practical 

utility, ways to enhance the quality, 

utility, and clarity of the information to 

be collected, and any suggested methods 

for minimizing respondents’ burden, 

including the use of automated 

information exchanges. The 

Commission did not receive any specific 

comments regarding its burden 

estimates. Where commenters raised 

concerns that specific information 

collection requirements would be 

burdensome to implement, the 


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12490 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

1001These burden estimates applied only to the 

Final Rule and do not reflect upon all of FERC–516 

or FERC–717. 

Commission has address those concerns 

elsewhere in the rule. 

1754. The Commission estimates the 

burden for complying with the Final 

Rule is as follows: 1001

Data collection Number of 

respondents 

Number of 

responses 

Hours per 

response 

Total annual 

hours 

Part 35 (FERC–516) 

Conforming tariff changes ............................................................................... 116 1 25 2,900 

Revision of Imbalance Charges ....................................................................... 116 1 5 580 

ATC revisions .................................................................................................. 116 1 40 4,640 

Planning (Attachment K) .................................................................................. 116 1 200 23,200 

Congestion studies .......................................................................................... 116 1 300 34,800 

Attestation of network resource commitment .................................................. 116 1 1 116 

Capacity reassignment .................................................................................... 116 1 100 11,600 

Operational Penalty annual filing ..................................................................... 116 1 10 1,160 

Creditworthiness—include criteria in the tariff ................................................. 116 1 40 4,640 

Sub Total Part 35 ..................................................................................... ........................ ........................ ........................ 83,636 

Part 37 (FERC–717) 

ATC-related standards: 

NERC/NAESB Team to develop .............................................................. 1 1 1,920 1,920 

Review and comment by utility ................................................................. 116 1 20 2,320 

Implementation by each utility .................................................................. 116 1 40 4,640 

Mandatory data exchanges ............................................................................. 116 1 80 9,280 

Explanation of change of ATC values ............................................................. 116 1 100 11,600 

Reevaluate CBM and post quarterly ............................................................... 116 1 20 2,320 

Post OASIS metrics; requests accepted/denied ............................................. 116 1 90 10,440 

Post planning redispatch offers and reliability redispatch data ....................... 116 1 20 2,320 

Post curtailment data ....................................................................................... 116 1 10 11,160 

Post Planning and System Impact Studies ..................................................... 116 1 5 580 

Posting of metrics for System Impact Studies ................................................ 116 1 100 11,600 

Post all rules to OASIS .................................................................................... 116 1 5 580 

Sub Total (Part 37) ................................................................................... ........................ ........................ ........................ 68,760 

Total (Part 35 + Part 37) ................................................................... ........................ ........................ ........................ 140,476 

Recordkeeping ................................................................................................. 116 1 40 4,640 

1755. Information Collection Costs: 

No comments were received regarding 

the Commission’s estimate of costs to 

comply with these requirements. The 

Commission has projected costs of 

compliance as follows: 

Total Annual Hours for Collection: 

Reporting + recordkeeping hours = 

152,396 + 4,640 = 157,036 hours. 

Cost to Comply: 

Reporting = $17,373,144 

152,396 hours @ $114 an hour 

(average cost of attorney ($200 per 

hour), consultant ($150), technical 

($80), and administrative support 

($25)) 

Recordkeeping = $7,478,888 

Labor (file/record clerk @ $17 an 

hour) 4,640 hours @ $17/hour = 

$78,880 

Storage 8,000 sq. ft. × $925 (off site 

storage) = $7,400,000 

Total costs = $24,852,024 

Labor $ ($17,373,144 + $78,880) + 

Recordkeeping Storage Costs 

($7,400,000) 

Title: FERC–516, Electric Rate 

Schedules and Tariff Filings; FERC–717 

Standards for Business Practices and 

Communication Protocols for Public 

Utilities. 

Action: Proposed Collections. 

OMB Control Nos. 1902–0096 and 

1902–0173. 

Respondents: Business or other for 

profit. 

Frequency of responses: On occasion. 

Necessity of the Information: The 

Federal Energy Regulatory Commission 

adopts these amendments to its 

regulations adopted in Order Nos. 888 

and 889, and to the pro forma open 

access transmission tariff, to ensure that 

transmission services are provided on a 

basis that is just, reasonable and not 

unduly discriminatory or preferential. 

The purpose of this rulemaking is to 

strengthen the pro forma OATT to 

ensure that it achieves its original 

purpose—remedying undue 

discrimination—not to create new 

market structures. We propose to 

achieve this goal by increasing the 

clarity and transparency of the rules 

applicable to the planning and use of 

the transmission system and by 

addressing ambiguities and the lack of 

sufficient detail in several important 

areas of the pro forma OATT. The lack 

of specificity in the pro forma OATT 

creates opportunities for undue 

discrimination as well as making the 

undue discrimination that does occur 

more difficult to detect. To accomplish 

this we are proposing five objectives: (1) 

To improve transparency and 

consistency in several critical areas, by 

providing for greater consistency in the 

calculation of ATC, (2) to reform the 

transmission planning requirements of 

the pro forma OATT to eliminate 

potential undue discrimination and 

support the construction of adequate 

transmission facilities to meet the needs 

of all LSEs, (3) to remedy certain 

portions of the pro forma OATT that 

may have permitted utilities to 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12491 

1002Regulations Implementing the National 

Environmental Policy Act, Order No. 486, 52 FR 

47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 

(1987). 

1003 18 CFR 380.4(a)(15). 

1004 5 U.S.C. 601–612. 

1005 The Commission has identified 116 

transmission providers with tariffs on file. We note 

that this figure is lower than our initial estimate in 

the NOPR, based on FERC Form No. 1 and FERC 

Form No. 1–F data. 

1006 Id. 

1007The Regulatory Flexibility Act defines a 

‘‘small entity’’ as ‘‘one which is independently 

owned and operated and which is not dominant in 

its field of operation.’’ See 5 U.S.C. 601(3) and 

601(6); 15 U.S.C. 632(a)(1). In Mid-Tex Elec. Coop. 

v. FERC, 773 F.2d 327, 340–43 (D.C. Cir. 1985), the 

court accepted the Commission’s conclusion that, 

since virtually all of the public utilities that it 

regulates do not fall within the meaning of the term 

‘‘small entities’’ as defined in the Regulatory 

Flexibility Act, the Commission did not need to 

prepare a regulatory flexibility analysis in 

connection with its proposed rule governing the 

allocation of costs for construction work in progress 

(CWIP). The CWIP rules applied to all public 

utilities. The revised pro forma OATT will apply 

only to those public utilities that own, control or 

operate interstate transmission facilities. These 

entities are a subset of the group of public utilities 

found not to require preparation of a regulatory 

flexibility analysis for the CWIP rule. 

discriminate against new merchant 

generation, including intermittent 

generation, (4) to provide for greater 

transparency in the provision of 

transmission service to allow 

transmission customers better access to 

information to make their resource 

procurement and investment decisions, 

as well as to increase the Commission’s 

ability to detect any remaining incidents 

of undue discrimination; and (5) to 

reform and provide greater clarity in 

areas that have generated recurring 

disputes over the past 10 years, such as 

rollover rights, ‘‘redirects,’’ and 

generation redispatch. The reforms 

proposed in this Final Rule are intended 

to address deficiencies in the pro forma 

OATT that have become apparent since 

the implementation of Order No. 888 in 

1996 and to facilitate improved 

planning and operation of transmission 

facilities. 

1756. Interested persons may obtain 

information on the reporting 

requirements by contacting the 

following: Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, Attention: 

Michael Miller, Office of the Executive 

Director, Phone: (202) 502–8415, fax: 

(202) 273–0873, e-mail: 

michael.miller@ferc.gov. 

1757. For submitting comments 

concerning the collections of 

information and the associated burden 

estimate(s), please send your comments 

to the contact listed above and to the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget, 725 17th Street, NW., 

Washington, DC 20503 Attention: Desk 

Officer for the Federal Energy 

Regulatory Commission, phone (202) 

395–3122, fax: (202) 395–7285. Due to 

security concerns, comments should be 

sent electronically to the following email address: 

oira_submission@omb.eop.gov. Please 

reference the docket number of this 

rulemaking in your submission. 

VII. Environmental Analysis 

1758. The Commission is required to 

prepare an Environmental Assessment 

or an Environmental Impact Statement 

for any action that may have a 

significant adverse effect on the human 

environment.1002 The Commission 

concludes that neither an 

Environmental Assessment nor an 

Environmental Impact Statement is 

required for this Final Rule under 

section 380.4(a)(15) of the Commission’s 

regulations, which provides a 

categorical exemption for approval of 

actions under sections 205 and 206 of 

the FPA relating to the filing of 

schedules containing all rates and 

charges for the transmission or sale 

subject to the Commission’s 

jurisdiction, plus the classification, 

practices, contracts and regulations that 

affect rates, charges, classifications and 

services.1003

VIII. Regulatory Flexibility Act 

Analysis 

1759. The Regulatory Flexibility Act 

of 1980 (RFA) 1004 generally requires a 

description and analysis of final rules 

that will have significant economic 

impact on a substantial number of small 

entities. This rule applies to public 

utilities that own, control or operate 

interstate transmission facilities other 

than those that have received waiver of 

the obligation to comply with Order 

Nos. 888 and 889. The total number of 

public utilities that, absent waiver, 

would have to modify their current 

OATTs by filing the revised pro forma 

OATT is 116.1005 Of these only six 

public utilities, or less than two percent, 

have output of four million MWh or less 

per year.1006 The Commission does not 

consider this a substantial number and, 

in any event, each of these entities 

retains its rights to waiver of these 

requirements.1007 The criteria for waiver 

that would be applied under this 

rulemaking for small entities is 

unchanged from that used to evaluate 

requests for waiver under Order Nos. 

888 and 889. Accordingly, the 

Commission certifies that the Final Rule 

will not have a significant economic 

impact on a substantial number of small 

entities. 

IX. Document Availability 

1760. In addition to publishing the 

full text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through the 

Commission’s Home Page (http:// 

www.ferc.gov) and in the Commission’s 

Public Reference Room during normal 

business hours (8:30 a.m. to 5 p.m. 

Eastern time) at 888 First Street, NE., 

Room 2A, Washington DC 20426. 

1761. From the Commission’s Home 

Page on the Internet, this information is 

available in the Commission’s document 

management system, eLibrary. The full 

text of this document is available on 

eLibrary in PDF and Microsoft Word 

format for viewing, printing, and/or 

downloading. To access this document 

in eLibrary, type ‘‘RM05–25’’ or 

‘‘RM05–17’’ in the docket number field. 

1762. User assistance is available for 

eLibrary and the Commission’s website 

during normal business hours. For 

assistance, please contact the 

Commission’s Online Support at 1–866–

208–3676 (toll free) or 202–502–6652 (email at FERCOnlineSupport@FERC.gov), 

or the Public Reference Room at 202–

502–8371, TTY 202–502–8659 (e-mail at 

public.referenceroom@ferc.gov). 

X. Effective Date and Congressional 

Notification 

1763. These regulations are effective 

May 14, 2007. The Commission has 

determined, with the concurrence of the 

Administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a ‘‘major rule’’

as defined in section 351 of the Small 

Business Regulatory Enforcement 

Fairness Act of 1996. The Commission 

will submit the Final Rule to both 

houses of Congress and to the General 

Accounting Office. 

List of Subjects 

18 CFR Part 35 

Electric power rates, Electric utilities, 

Reporting and recordkeeping 

requirements. 

18 CFR Part 37 

Conflict of interests, Electric power 

plants, Electric utilities, Reporting and 

recordkeeping requirements. 

By the Commission. 

Magalie R. Salas, 

Secretary. 

■ In consideration of the foregoing, the 

Commission amends parts 35 and 37, 


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12492 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

Chapter I, Title 18 of the Code of 

Federal Regulations, as follows: 

PART 35—FILING OF RATE 

SCHEDULES AND TARIFFS 

■ 1. The authority citation for part 35 

continues to read as follows: 

Authority: 16 U.S.C. 791a–825r, 2601–

2645; 31 U.S.C. 9701; 42 U.S.C. 71–7352. 

■ 2. Amend § 35.28 as follows: 

■ a. Paragraph (c) is revised. 

■ b. Paragraphs (d)(i) and (d)(ii) are 

redesignated as paragraphs (d)(1) and 

(d)(2). 

■ c. Newly redesignated paragraph 

(d)(1) is revised. 

■ d. Paragraph (e)(1) introductory text is 

revised. 

■ e. Paragraph (e)(1)(ii) is revised. 

§ 35.28 Non-discriminatory open access 

transmission tariff. 

* * * * * 

(c) Non-discriminatory open access 

transmission tariffs. (1) Every public 

utility that owns, controls, or operates 

facilities used for the transmission of 

electric energy in interstate commerce 

must have on file with the Commission 

a tariff of general applicability for 

transmission services, including 

ancillary services, over such facilities. 

Such tariff must be the open access pro 

forma tariff contained in Order No. 888, 

FERC Stats. & Regs. ¶ 31,036 (Final Rule 

on Open Access and Stranded Costs), as 

revised by the open access pro forma 

tariff contained in Order No. 890, FERC 

Stats. & Regs. ¶ 31,241 (Final Rule on 

Open Access Reforms), or such other 

open access tariff as may be approved 

by the Commission consistent with 

Order No. 888, FERC Stats. & Regs 

¶ 31,306 and Order No. 890, FERC Stats. 

& Regs. ¶ 31,241. 

(i) Subject to the exceptions in 

paragraphs (c)(1)(ii), (c)(1)(iii), (c)(1)(iv) 

and (c)(1)(v) of this section, the pro 

forma tariff contained in Order No. 888, 

FERC Stats. & Regs. ¶ 31,036, as revised 

by the open access pro forma tariff 

contained in Order No. 890, FERC Stats. 

& Regs. ¶ 31,241, and accompanying 

rates, must be filed no later than 60 days 

prior to the date on which a public 

utility would engage in a sale of electric 

energy at wholesale in interstate 

commerce or in the transmission of 

electric energy in interstate commerce. 

(ii) If a public utility owns, controls, 

or operates facilities used for the 

transmission of electric energy in 

interstate commerce as of May 14, 2007, 

it must file the revisions to the pro 

forma tariff contained in Order No. 890, 

FERC Stats. & Regs. ¶ 31,241, pursuant 

to section 206 of the FPA and 

accompanying rates pursuant to section 

205 of the FPA in accordance with the 

procedures set forth in Order No. 890, 

FERC Stats. & Regs ¶ 31,241. 

(iii) If a public utility owns, controls, 

or operates transmission facilities used 

for the transmission of electric energy in 

interstate commerce as of May 14, 2007, 

such facilities are jointly owned with a 

non-public utility, and the joint 

ownership contract prohibits 

transmission service over the facilities 

to third parties, the public utility with 

respect to access over the public utility’s 

share of the jointly owned facilities 

must file no later than May 14, 2007 the 

revisions to the pro forma tariff 

contained in Order No. 890, FERC Stats. 

& Regs. ¶ 31,241, pursuant to section 

206 of the FPA and accompanying rates 

pursuant to section 205 of the FPA. 

(iv) Any public utility whose 

transmission facilities are under the 

independent control of a Commissionapproved ISO or RTO may satisfy its 

obligation under paragraph (c)(1) of this 

section, with respect to such facilities, 

through the open access transmission 

tariff filed by the ISO or RTO. 

(v) If a public utility obtains a waiver 

of the tariff requirement pursuant to 

paragraph (d) of this section, it does not 

need to file the pro forma tariff required 

by this section. 

(vi) Any public utility that seeks a 

deviation from the pro forma tariff 

contained in Order No. 888, FERC Stats. 

& Regs. ¶ 31,036, as revised in Order No. 

890, FERC Stats. & Regs. ¶ 31,241, must 

demonstrate that the deviation is 

consistent with the principles of Order 

No. 888, FERC Stats. & Regs ¶ 31,036 

and Order No. 890, FERC Stats. & Regs. 

¶ 31,241. 

(vii) Each public utility’s open access 

transmission tariff must include the 

standards incorporated by reference in 

part 38 of this chapter. 

(2) Subject to the exceptions in 

paragraphs (c)(2)(i) and (c)(3)(iii) of this 

section, every public utility that owns, 

controls, or operates facilities used for 

the transmission of electric energy in 

interstate commerce, and that uses those 

facilities to engage in wholesale sales 

and/or purchases of electric energy, or 

unbundled retail sales of electric energy, 

must take transmission service for such 

sales and/or purchases under the open 

access transmission tariff filed pursuant 

to this section. 

(i) For sales of electric energy 

pursuant to a requirements service 

agreement executed on or before July 9, 

1996, this requirement will not apply 

unless separately ordered by the 

Commission. For sales of electric energy 

pursuant to a bilateral economy energy 

coordination agreement executed on or 

before July 9, 1996, this requirement is 

effective on December 31, 1996. For 

sales of electric energy pursuant to a 

bilateral non-economy energy 

coordination agreement executed on or 

before July 9, 1996, this requirement 

will not apply unless separately ordered 

by the Commission. 

(ii) [Reserved.] 

(3) Every public utility that owns, 

controls, or operates facilities used for 

the transmission of electric energy in 

interstate commerce, and that is a 

member of a power pool, public utility 

holding company, or other multi-lateral 

trading arrangement or agreement that 

contains transmission rates, terms or 

conditions, must have on file a joint 

pool-wide or system-wide open access 

transmission tariff, which tariff must be 

the pro forma tariff contained in Order 

No. 888, FERC Stats. & Regs. ¶ 31,036, 

as revised by the pro forma tariff 

contained in Order No. 890, FERC Stats. 

& Regs. ¶ 31,241, or such other open 

access tariff as may be approved by the 

Commission consistent with Order No. 

888, FERC Stats. & Regs. ¶ 31,036 and 

Order No. 890, FERC Stats. & Regs. 

¶ 31,241. 

(i) For any power pool, public utility 

holding company or other multi-lateral 

arrangement or agreement that contains 

transmission rates, terms or conditions 

and that is executed after May 14, 2007, 

this requirement is effective on the date 

that transactions begin under the 

arrangement or agreement. 

(ii) For any power pool, public utility 

holding company or other multi-lateral 

arrangement or agreement that contains 

transmission rates, terms or conditions 

and that is executed on or before May 

14, 2007, a public utility member of 

such power pool, public utility holding 

company or other multi-lateral 

arrangement or agreement that owns, 

controls, or operates facilities used for 

the transmission of electric energy in 

interstate commerce must file the 

revisions to its joint pool-wide or 

system-wide contained in Order No. 

890, FERC Stats. & Regs. ¶ 31,241, 

pursuant to section 206 of the FPA and 

accompanying rates pursuant to section 

205 of the FPA in accordance with the 

procedures set forth in Order No. 890, 

FERC Stats. & Regs ¶ 31,241. 

(iii) A public utility member of a 

power pool, public utility holding 

company or other multi-lateral 

arrangement or agreement that contains 

transmission rates, terms or conditions 

and that is executed on or before July 9, 

1996 must take transmission service 

under a joint pool-wide or system-wide 

open access transmission tariff filed 

pursuant to this section for wholesale 

trades among the pool or system 

members. 


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(4) Consistent with paragraph (c)(1) of 

this section, every Commissionapproved ISO or RTO must have on file 

with the Commission a tariff of general 

applicability for transmission services, 

including ancillary services, over such 

facilities. Such tariff must be the pro 

forma tariff contained in Order No. 888, 

FERC Stats. & Regs. ¶ 31,036, as revised 

by the pro forma tariff contained in 

Order No. 890, FERC Stats. & Regs. 

¶ 31,241, or such other open access tariff 

as may be approved by the Commission 

consistent with Order No. 888, FERC 

Stats. & Reg. ¶ 31,036 and Order No. 

890, FERC Stats. & Regs. ¶ 31,241. 

(i) Subject to paragraph (c)(4)(ii) of 

this section, a Commission-approved 

ISO or RTO must file the revisions to 

the pro forma tariff contained in Order 

No. 890, FERC Stats. & Regs. ¶ 31,241, 

pursuant to section 206 of the FPA and 

accompanying rates pursuant to section 

205 of the FPA in accordance with the 

procedures set forth in Order No. 890, 

FERC Stats. & Regs ¶ 31,241. 

(ii) If a Commission-approved ISO or 

RTO can demonstrate that its existing 

open access tariff is consistent with or 

superior to the revisions to the pro 

forma tariff contained in Order No. 888, 

FERC Stats. & Regs. ¶ 31,036, as revised 

by the pro forma tariff in Order No. 890, 

FERC Stats. & Regs. ¶ 31,241, or any 

portions thereof, the Commissionapproved ISO or RTO may instead set 

forth such demonstration in its filing 

pursuant to section 206 in accordance 

with the procedures set forth in Order 

No. 890, FERC Stats. & Regs ¶ 31,241. 

(d) Waivers. * * * 

(1) No later than May 14, 2007, or 

* * * * * 

(e) Non-public utility procedures for 

tariff reciprocity compliance. (1) A nonpublic utility may submit a transmission 

tariff and a request for declaratory order 

that its voluntary transmission tariff 

meets the requirements of Order No. 

888, FERC Stats. & Regs. ¶ 31,036 and 

Order No. 890, FERC Stats. & Regs. 

¶ 31,241. 

* * * * * 

(ii) If the submittal is found to be an 

acceptable transmission tariff, an 

applicant in a Federal Power Act (FPA) 

section 211 or 211A proceeding against 

the non-public utility shall have the 

burden of proof to show why service 

under the open access tariff is not 

sufficient and why a section 211 or 

211A order should be granted. 

* * * * * 

PART 37—OPEN ACCESS SAME-TIME 

INFORMATION SYSTEMS 

■ 3. The authority citation for part 37 

continues to read as follows: 

Authority: 16 U.S.C. 791–825r, 2601–2645; 

31 U.S.C. 9701; 42 U.S.C. 7101–7352. 

■ 4. Amend § 37.6 as follows: 

■ a. Paragraph (a)(1) is revised. 

■ b. Paragraph (b) introductory text is 

revised. 

■ c. Paragraphs (b)(1)(v) through 

(b)(1)(viii) are added. 

■ d. Paragraphs (b)(2)(i) through 

(b)(2)(iii) are revised. 

■ e. Paragraph (b)(3) is revised. 

■ f. Paragraphs (c)(2) and (c)(5) are 

revised. 

■ g. Paragraphs (e)(1) and (e)(2)(ii) are 

revised. 

■ h. Paragraph (e)(3)(ii) is revised. 

■ i. Paragraphs (h), (i) and (j) are added. 

§ 37.6 Information to be posted on the 

OASIS. 

(a) * * * 

(1) Make requests for transmission 

services offered by Transmission 

Providers, Resellers and other providers 

of ancillary services, request the 

designation of a network resource, and 

request the termination of the 

designation of a network resource; 

* * * * * 

(b) Posting transfer capability. The 

available transfer capability on the 

Transmission Provider’s system (ATC) 

and the total transfer capability (TTC) of 

that system shall be calculated and 

posted for each Posted Path as set out 

in this section. 

(1) * * * 

(v) Available transfer capability or 

ATC means the transfer capability 

remaining in the physical transmission 

network for further commercial activity 

over and above already committed uses, 

or such definition as contained in 

Commission-approved Reliability 

Standards. 

(vi) Total transfer capability or TTC 

means the amount of electric power that 

can be moved or transferred reliably 

from one area to another area of the 

interconnected transmission systems by 

way of all transmission lines (or paths) 

between those areas under specified 

system conditions, or such definition as 

contained in Commission-approved 

Reliability Standards. 

(vii) Capacity Benefit Margin or CBM 

means the amount of TTC preserved by 

the Transmission Provider for loadserving entities, whose loads are located 

on that Transmission Provider’s system, 

to enable access by the load-serving 

entities to generation from 

interconnected systems to meet 

generation reliability requirements, or 

such definition as contained in 

Commission-approved Reliability 

Standards. 

(viii) Transmission Reliability Margin 

or TRM means the amount of TTC 

necessary to provide reasonable 

assurance that the interconnected 

transmission network will be secure, or 

such definition as contained in 

Commission-approved Reliability 

Standards. 

(2) * * * 

(i) Information used to calculate any 

posting of ATC and TTC must be dated 

and time-stamped and all calculations 

shall be performed according to 

consistently applied methodologies 

referenced in the Transmission 

Provider’s transmission tariff and shall 

be based on Commission-approved 

Reliability Standards as well as current 

industry practices, standards and 

criteria. 

(ii) On request, the Responsible Party 

must make all data used to calculate 

ATC, TTC, CBM, and TRM for any 

constrained posted paths publicly 

available (including the limiting 

element(s) and the cause of the limit 

(e.g., thermal, voltage, stability), as well 

as load forecast assumptions) in 

electronic form within one week of the 

posting. The information is required to 

be provided only in the electronic 

format in which it was created, along 

with any necessary decoding 

instructions, at a cost limited to the cost 

of reproducing the material. This 

information is to be retained for six 

months after the applicable posting 

period. 

(iii) System planning studies, 

facilities studies, and specific network 

impact studies performed for customers 

or the Transmission Provider’s own 

network resources are to be made 

publicly available in electronic form on 

request and a list of such studies shall 

be posted on the OASIS. A study is 

required to be provided only in the 

electronic format in which it was 

created, along with any necessary 

decoding instructions, at a cost limited 

to the cost of reproducing the material. 

These studies are to be retained for five 

years. 

(3) Posting. The ATC, TTC, CBM, and 

TRM for all Posted Paths must be posted 

in megawatts by specific direction and 

in the manner prescribed in this 

subsection. 

(i) Constrained posted paths.—(A) For 

firm ATC and TTC. 

(1) The posting shall show ATC, TTC, 

CBM, and TRM for a 30-day period. For 

this period postings shall be: by the 

hour, for the current hour and the 168 

hours next following; and thereafter, by 

the day. If the Transmission Provider 

charges separately for on-peak and offpeak periods in its tariff, ATC, TTC, 

CBM, and TRM will be posted daily for 

each period. 


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12494 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

(2) Postings shall also be made by the 

month, showing for the current month 

and the 12 months next following. 

(3) If planning and specific requested 

transmission studies have been done, 

seasonal capability shall be posted for 

the year following the current year and 

for each year following to the end of the 

planning horizon but not to exceed 10 

years. 

(B) For non-firm ATC and TTC. The 

posting shall show ATC, TTC, CBM and 

TRM for a 30-day period by the hour 

and days prescribed under paragraph 

(b)(3)(i)(A)(1) of this section and, if so 

requested, by the month and year as 

prescribed under paragraph (b)(3)(i)(A) 

(2) and (3) of this section. The posting 

of non-firm ATC and TTC shall show 

CBM as zero. 

(C) Updating posted information for 

constrained paths. 

(1) The capability posted under 

paragraphs (b)(3)(i)(A) and (B) of this 

section must be updated when 

transactions are reserved or service ends 

or whenever the estimate for the path 

changes by more than 10 percent. 

(2) All updating of hourly information 

shall be made on the hour. 

(3) When the monthly and yearly 

capability posted under paragraphs 

(b)(3)(i)(A) and (B) of this section are 

updated because of a change in TTC by 

more than 10 percent, the Transmission 

Provider shall post a brief, but specific, 

narrative explanation of the reason for 

the update. This narrative should 

include, the specific events which gave 

rise to the update (e.g., scheduling of 

planned outages and occurrence of 

forced transmission outages, de-ratings 

of transmission facilities, scheduling of 

planned generation outages and 

occurrence of forced generation outages, 

changes in load forecast, changes in new 

facilities’ in-service dates, or other 

events or assumption changes) and new 

values for ATC on the path (as opposed 

to all points on the network). 

(4) When the monthly and yearly 

capability posted under paragraphs 

(b)(3)(i)(A) and (B) of this section 

remain unchanged at a value of zero for 

a period of six months, the 

Transmission Provider shall post a brief, 

but specific, narrative explanation of the 

reason for the unavailability of ATC. 

(ii) Unconstrained posted paths. 

(A) Postings of firm and nonfirm ATC, 

TTC, CBM, and TRM shall be posted 

separately by the day, showing for the 

current day and the next six days 

following and thereafter, by the month 

for the 12 months next following. If the 

Transmission Provider charges 

separately for on-peak and off-peak 

periods in its tariff, ATC, TTC, CBM, 

and TRM will be posted separately for 

the current day and the next six days 

following for each period. These 

postings are to be updated whenever the 

ATC changes by more than 20 percent 

of the Path’s TTC. 

(B) If planning and specific requested 

transmission studies have been done, 

seasonal capability shall be posted for 

the year following the current year and 

for each year following until the end of 

the planning horizon but not to exceed 

10 years. 

(iii) Calculation of CBM. 

(A) The Transmission Provider must 

reevaluate its CBM needs at least every 

year. 

(B) The Transmission Provider must 

post its practices for reevaluating its 

CBM needs. 

(iv) Daily load. The Transmission 

Provider must post on a daily basis, its 

actual daily peak load for the prior day. 

(c) * * * 

(2) Transmission Providers must 

provide a downloadable file of their 

complete tariffs in the same electronic 

format as the tariff that is filed with the 

Commission. Transmission Providers 

also must provide a link to all of the 

rules, standards and practices that relate 

to transmission services posted on the 

Transmission Providers’ public Web 

sites. 

* * * * * 

(5) Customers choosing to use the 

OASIS to offer for resale transmission 

capacity they have purchased must post 

relevant information to the same OASIS 

as used by the Transmission Provider 

from whom the Reseller purchased the 

transmission capacity. This information 

must be posted on the same display 

page, using the same tables, as similar 

capability being sold by the 

Transmission Provider, and the 

information must be contained in the 

same downloadable files as the 

Transmission Provider’s own available 

capability. 

* * * * * 

(e) Posting specific transmission and 

ancillary service requests and responses. 

(1) General rules. 

(i) All requests for transmission and 

ancillary service offered by 

Transmission Providers under the pro 

forma tariff, including requests for 

discounts, and all requests to designate 

or terminate a network resource, must 

be made on the OASIS and posted prior 

to the Transmission Provider 

responding to the request, except as 

discussed in paragraphs (e)(1)(ii) and 

(iii) of this section. The Transmission 

Provider must post all requests for 

transmission service, for ancillary 

service, and for the designation or 

termination of a network resource 

comparably. Requests for transmission 

service, ancillary service, and to 

designate and terminate a network 

resource, as well as the responses to 

such requests, must be conducted in 

accordance with the Transmission 

Provider’s tariff, the Federal Power Act, 

and Commission regulations. 

(ii) The requirement in paragraph 

(e)(1)(i) of this section, to post requests 

for transmission and ancillary service 

offered by Transmission Providers 

under the pro forma tariff, including 

requests for discounts, prior to the 

Transmission Provider responding to 

the request, does not apply to requests 

for next-hour service made during Phase 

I. 

(iii) In the event that a discount is 

being requested for ancillary services 

that are not in support of basic 

transmission service provided by the 

Transmission Provider, such request 

need not be posted on the OASIS. 

(iv) In processing a request for 

transmission or ancillary service, the 

Responsible Party shall post the same 

information as required in paragraphs 

(c)(4) and (d)(3) of this section, and the 

following information: the date and time 

when the request is made, its place in 

any queue, the status of that request, 

and the result (accepted, denied, 

withdrawn). In processing a request to 

designate or terminate the designation 

of a network resource, the Responsible 

Party shall post the date and time when 

the request is made. 

(v) For any request to designate or 

terminate a network resource, the 

Transmission Provider (at the time 

when the request is received), must post 

on the OASIS (and make available for 

download) information describing the 

request (including: name of requestor, 

identification of the resource, effective 

time for the designation or termination, 

identification of whether the transaction 

involves the Transmission Provider’s 

wholesale merchant function or any 

affiliate; and any other relevant terms 

and conditions) and shall keep such 

information posted on the OASIS for at 

least 30 days. A record of the 

transaction must be retained and kept 

available as part of the audit log 

required in § 37.7. 

(vi) The Transmission Provider shall 

post a list of its current designated 

network resources and all network 

customers’ current designated network 

resources on OASIS. The list of network 

resources should include the name of 

the resource, its geographic and 

electrical location, its total installed 

capacity, and the amount of capacity to 

be designated as a network resource. 

(2) * * * 


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(ii) Information to support the reason 

for the denial, including the operating 

status of relevant facilities, must be 

maintained for five years and provided, 

upon request, to the potential 

Transmission Customer and the 

Commission’s Staff. 

* * * * * 

(3) * * * 

(ii) Information to support any such 

curtailment or interruption, including 

the operating status of the facilities 

involved in the constraint or 

interruption, must be maintained and 

made available upon request, to the 

curtailed or interrupted customer, the 

Commission’s Staff, and any other 

person who requests it, for five years. 

* * * * * 

(h) Posting information summarizing 

the time to complete transmission 

service request studies. (1) For each 

calendar quarter, the Responsible Party 

must post the set of measures detailed 

in paragraph (h)(1)(i) through paragraph 

(h)(1)(vi) of this section related to the 

Responsible Party’s processing of 

transmission service request system 

impact studies and facilities studies. 

The Responsible Party must calculate 

and post the measures in paragraph 

(h)(1)(i) through paragraph (h)(1)(vi) of 

this section separately for requests for 

short-term firm point-to-point 

transmission service, long-term firm 

point-to-point transmission service, and 

requests to designate a new network 

resource and must be calculated and 

posted separately for transmission 

service requests from Affiliates and 

transmission service requests from 

Transmission Customers who are not 

Affiliates. The Responsible Party is 

required to include in the calculations 

of the measures in paragraph (h)(1)(i) 

through paragraph (h)(1)(vi) of this 

section all studies the Responsible Party 

conducts of transmission service 

requests on another Transmission 

Provider’s OASIS. 

(i) Process time from initial service 

request to offer of system impact study 

agreement. 

(A) Number of new system impact 

study agreements delivered during the 

reporting quarter to entities that request 

transmission service, 

(B) Number of new system impact 

study agreements delivered during the 

reporting quarter to entities that request 

transmission service more than thirty 

(30) days after the Responsible Party 

received the request for transmission 

service, 

(C) Mean time (in days), for all 

requests acted on by the Responsible 

Party during the reporting quarter, from 

the date when the Responsible Party 

received the request for transmission 

service to when the Responsible Party 

changed the transmission service 

request status to indicate that the 

Responsible Party could offer 

transmission service or needed to 

perform a system impact study, 

(D) Mean time (in days), for all system 

impact study agreements delivered by 

the Responsible Party during the 

reporting quarter, from the date when 

the Responsible Party received the 

request for transmission service to the 

date when the Responsible Party 

delivered a system impact study 

agreement, and 

(E) Number of new system impact 

study agreements executed during the 

reporting quarter. 

(ii) System impact study processing 

time. 

(A) Number of system impact studies 

completed by the Responsible Party 

during the reporting quarter, 

(B) Number of system impact studies 

completed by the Responsible Party 

during the reporting quarter more than 

60 days after the Responsible Party 

received an executed system impact 

study agreement, 

(C) For all system impact studies 

completed more than 60 days after 

receipt of an executed system impact 

study agreement, average number of 

days study was delayed due to 

transmission customer’s actions (e.g., 

delays in providing needed data), 

(D) Mean time (in days), for all system 

impact studies completed by the 

Responsible Party during the reporting 

quarter, from the date when the 

Responsible Party received the executed 

system impact study agreement to the 

date when the Responsible Party 

provided the system impact study to the 

entity who executed the system impact 

study agreement, and 

(E) Mean cost of system impact 

studies completed by the Responsible 

Party during the reporting quarter. 

(iii) Transmission service requests 

withdrawn from the system impact 

study queue. 

(A) Number of transmission service 

requests withdrawn from the 

Responsible Party’s system impact study 

queue during the reporting quarter, 

(B) Number of transmission service 

requests withdrawn from the 

Responsible Party’s system impact study 

queue during the reporting quarter more 

than 60 days after the Responsible Party 

received the executed system impact 

study agreement, and 

(C) Mean time (in days), for all 

transmission service requests 

withdrawn from the Responsible Party’s 

system impact study queue during the 

reporting quarter, from the date the 

Responsible Party received the executed 

system impact study agreement to date 

when request was withdrawn from the 

Responsible Party’s system impact study 

queue. 

(iv) Process time from completed 

system impact study to offer of facilities 

study. 

(A) Number of new facilities study 

agreements delivered during the 

reporting quarter to entities that request 

transmission service, 

(B) Number of new facilities study 

agreements delivered during the 

reporting quarter to entities that request 

transmission service more than thirty 

(30) days after the Responsible Party 

completed the system impact study, 

(C) Mean time (in days), for all 

facilities study agreements delivered by 

the Responsible Party during the 

reporting quarter, from the date when 

the Responsible Party completed the 

system impact study to the date when 

the Responsible Party delivered a 

facilities study agreement, and 

(D) Number of new facilities study 

agreements executed during the 

reporting quarter. 

(v) Facilities study processing time. 

(A) Number of facilities studies 

completed by the Responsible Party 

during the reporting quarter, 

(B) Number of facilities studies 

completed by the Responsible Party 

during the reporting quarter more than 

60 days after the Responsible Party 

received an executed facilities study 

agreement, 

(C) For all facilities studies completed 

more than 60 days after receipt of an 

executed facilities study agreement, 

average number of days study was 

delayed due to transmission customer’s 

actions (e.g., delays in providing needed 

data), 

(D) Mean time (in days), for all 

facilities studies completed by the 

Responsible Party during the reporting 

quarter, from the date when the 

Responsible Party received the executed 

facilities study agreement to the date 

when the Responsible Party provided 

the facilities study to the entity who 

executed the facilities study agreement, 

(E) Mean cost of facilities studies 

completed by the Responsible Party 

during the reporting quarter, and 

(F) Mean cost of upgrades 

recommended in facilities studies 

completed during the reporting quarter. 

(vi) Service requests withdrawn from 

facilities study queue. 

(A) Number of transmission service 

requests withdrawn from the 

Responsible Party’s facilities study 

queue during the reporting quarter, 

(B) Number of transmission service 

requests withdrawn from the 


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Responsible Party’s facilities study 

queue during the reporting quarter more 

than 60 days after the Responsible Party 

received the executed facilities study 

agreement, and 

(C) Mean time (in days), for all 

transmission service requests 

withdrawn from the Responsible Party’s 

facilities study queue during the 

reporting quarter, from the date the 

Responsible Party received the executed 

facilities study agreement to date when 

request was withdrawn from the 

Responsible Party’s facilities study 

queue. 

(2) The Responsible Party is required 

to post the measures in paragraph 

(h)(1)(i) through paragraph (h)(1)(vi) of 

this section for each calendar quarter 

within 15 days of the end of the 

calendar quarter. The Responsible Party 

will keep the quarterly measures posted 

on OASIS for three calendar years. 

(3) The Responsible Party will be 

required to post on OASIS the measures 

in paragraph (h)(3)(i) through paragraph 

(h)(3)(iv) of this section in the event the 

Responsible Party, for two consecutive 

calendar quarters, completes more than 

twenty (20) percent of the studies 

associated with requests for 

transmission service from entities that 

are not Affiliates of the Responsible 

Party more than sixty (60) days after the 

Responsible Party delivers the 

appropriate study agreement. The 

Responsible Party will have to post the 

measures in paragraph (h)(3)(i) through 

paragraph (h)(3)(iv) of this section until 

it processes at least ninety (90) percent 

of all studies within 60 days after it has 

received the appropriate executed study 

agreement. For the purposes of 

calculating the percent of studies 

completed more than sixty (60) days 

after the Responsible Party delivers the 

appropriate study agreement, the 

Responsible Party should aggregate all 

system impact studies and facilities 

studies that it completes during the 

reporting quarter. The Responsible Party 

must calculate and post the measures in 

paragraph (h)(3)(i) through paragraph 

(h)(3)(iv) of this section separately for 

requests for short-term firm point-topoint transmission service, long-term 

firm point-to-point transmission service, 

and requests to designate a new network 

resource and must be calculated and 

posted separately for transmission 

service requests from Affiliates and 

transmission service requests from 

Transmission Customers who are not 

Affiliates. 

(i) Mean, across all system impact 

studies the Responsible Party completes 

during the reporting quarter, of the 

employee-hours expended per system 

impact study the Responsible Party 

completes during reporting period; 

(ii) Mean, across all facilities studies 

the Responsible Party completes during 

the reporting quarter, of the employeehours expended per facilities study the 

Responsible Party completes during 

reporting period; 

(iii) The number of employees the 

Responsible Party has assigned to 

process system impact studies; 

(iv) The number of employees the 

Responsible Party has assigned to 

process facilities studies. 

(4) The Responsible Party is required 

to post the measures in paragraph 

(h)(3)(i) through paragraph (h)(3)(iv) of 

this section for each calendar quarter 

within 15 days of the end of the 

calendar quarter. The Responsible Party 

will keep the quarterly measures posted 

on OASIS for five calendar years. 

(i) Posting data related to grants and 

denials of service. The Responsible 

Party is required to post data each 

month listing, by path or flowgate, the 

number of transmission service requests 

that have been accepted and the number 

of transmission service requests that 

have been denied during the prior 

month. This posting must distinguish 

between the length of the service 

request (e.g., short-term or long-term 

requests) and between the type of 

service requested (e.g., firm point-topoint, non-firm point-to-point or 

network service). The posted data must 

show: 

(1) The number of non-Affiliate 

requests for transmission service that 

have been rejected, 

(2) The total number of non-Affiliate 

requests for transmission service that 

have been made, 

(3) The number of Affiliate requests 

for transmission service that have been 

rejected, and 

(4) The total number of Affiliate 

requests for transmission service that 

have been made. 

(j) Posting redispatch data. 

(1) The Transmission Provider must 

allow the posting on OASIS of any third 

party offer to relieve a specified 

congested transmission facility. 

(2) The Transmission Provider must 

post on OASIS (i) its monthly average 

cost of planning and reliability 

redispatch, for which it invoices 

customers, at each internal transmission 

facility or interface over which it 

provides redispatch service and (ii) a 

high and low redispatch cost for the 

month for each of these same 

transmission facilities. The transmission 

provider must post this data on OASIS 

as soon as practical after the end of each 

month, but no later than when it sends 

invoices to transmission customers for 

redispatch-related services. 

■ 5. In § 37.7, paragraph (b) is revised to 

read as follows: 

§ 37.7 Auditing Transmission Service 

Information. 

* * * * * 

(b) Audit data must remain available 

for download on the OASIS for 90 days, 

except ATC/TTC postings that must 

remain available for download on the 

OASIS for 20 days. The audit data are 

to be retained and made available upon 

request for download for five years from 

the date when they are first posted in 

the same electronic form as used when 

they originally were posted on the 

OASIS. 

Note: The following appendices will not be 

published in the Code of Federal 

Regulations. 

Appendix A: Summary of Compliance 

Filing Requirements 

For a more detailed description of 

compliance obligations please refer to 

the Final Rule paragraph number. For 

further information related to the Final 

Rule, such as electronic versions of the 

pro forma OATT showing tariff changes 

adopted in the Final Rule in redline/ 

strikeout format, and further 

information regarding docketing of 

compliance filings and specific filing 

instructions, please visit our Web site at 

the following location http:// 

www.ferc.gov/industries/electric/indusact/oatt-reform.asp. 

Deadline (days after publication 

in Federal Register) Compliance action Final rule paragraph No. 

30 .............................................. Optional Implementation FPA section 205 filings allowing transmission providers to propose 

previously approved variations from the pro forma OATT that have been affected by pro 

forma OATT Final Rule reforms to remain in effect subject to a demonstration that such 

variations continue to be consistent with or superior to the revised Final Rule pro forma 

OATT (non RTO/ISO transmission providers). Such optional filings must request a 90 day 

effective date to facilitate Commission review under section 205.

P 139 


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Deadline (days after publication 

in Federal Register) Compliance action Final rule paragraph No. 

60 .............................................. Non-ISO/RTO transmission providers submit FPA section 206 filings that contain the non-rate 

terms and conditions set forth in Final Rule. These filings need only contain the revised 

provisions adopted in the Final Rule. Transmission providers utilizing the optional Implementation FPA section 205 filing described above, need only submit tariff sheets necessary 

to implement the remaining modifications required under the Final Rule, i.e., modifications 

related to tariff provisions that did not implicate previously-approved variations.

P 135 

75 .............................................. Transmission Providers must post a ‘‘strawman’’ proposal for compliance with each of the 

nine planning principles adopted in the Final Rule. This may be posted on the Transmission Providers Web site or its OASIS site.

P 443 

90 .............................................. NERC/NAESB status report and work plan for completion of ATC related business practices 

and standards.

P 223 

NAESB status report and work plan for completion of OASIS functionality or uniform business 

practices (other than those related to ATC).

P 141 

120 ............................................ Transmission Providers must submit redesigned transmission charges that reflect the Capacity Benefit Margin set-aside through a limited issue section 205 rate filing as part of their 

initial ATC related compliance filings.

P 263 

180 ............................................ Submit compliance filings with Attachment C (ATC) of the pro forma OATT ............................. P 140 

210 ............................................ ISOs and RTOs, and transmission providers located within an ISO/RTO footprint, submit FPA 

section 206 filings that contain the non-rate terms and conditions set forth in the Final Rule. 

These filings need only contain the revised provisions adopted in the Final Rule or a demonstration that previously approved variations continue to be consistent with or superior to 

the revised pro forma OATT.

P 157, P 161 

210 ............................................ Submit compliance filings with Attachment K (Planning) of the pro forma OATT or RTOs and 

ISOs file a demonstration that their planning processes are consistent with or superior to 

the planning principles in the Final Rule.

P 140, P 442 

N/A ............................................ Transmission Providers must file a revised Attachment C to incorporate any changes to 

NERC’s and NAESB’s reliability and business practice standards to achieve consistency in 

ATC within 60 days of completion of the NERC and NAESB processes.

P 325 

N/A ............................................ After the submission of FPA section 206 compliance filings, transmission providers may submit FPA section 205 filings proposing rates for the services provided for in the tariff, as well 

as non-rate terms and conditions that differ from those set forth in the Final Rule if those 

provisions are ‘‘consistent with or superior to’’ the pro forma OATT.

P 135 

Appendix B: Commenting Party 

Acronyms 

INITIAL COMMENTERS

Abbreviation Initial commenters 

Alberta Intervenors ............................................................. Alberta Intervenors (TransCanada Energy Ltd., ENMAX Energy Marketing, Inc.; 

EPCOR Merchant and Capital, LP; and TransAlta Corporation). 

Alcoa .................................................................................. Alcoa Inc. and Alcoa Power Generating Inc. 

Allegheny ............................................................................ Allegheny Power and Allegheny Energy Supply Company, LLC. 

Ameren ............................................................................... Ameren Services Company. 

American Transmission ...................................................... American Transmission Company LLC. 

AMP-Ohio ........................................................................... American Municipal Power-Ohio, Inc. 

Anaheim ............................................................................. Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California. 

APPA .................................................................................. American Public Power Association. 

ARC .................................................................................... Alliance for Retail Choice. 

Arkansas Commission ....................................................... Arkansas Public Service Commission. 

Arkansas Municipal ............................................................ Arkansas Municipal Power Association. 

AWEA ................................................................................. American Wind Energy Association. 

Barrick ................................................................................ Barrick Goldstrike Mines Inc. 

BART .................................................................................. San Francisco Bay Area Rapid Transit District. 

Bonneville ........................................................................... Bonneville Power Administration. 

BP Energy .......................................................................... BP Energy Company. 

Bureau of Reclamation ...................................................... U.S. Bureau of Reclamation. 

CAC/EPUC ......................................................................... Cogeneration Association of California (Coalinga Cogeneration Co., Mid-Set Cogeneration Co., Kern River Cogeneration Co., Sycamore Cogeneration Co., Sargent 

Canyon Cogeneration Co., Salinas River Cogeneration Co., Midwest Sunset Cogeneration Co. and Watson Cogeneration Co.) and Energy Producers and Users 

Coalition (Aera Energy LLC, BP American, Inc., Chevron USA, Inc., ConocoPhilips 

Co., ExxonMobil Power and Gas Services, Inc., Shell Oil Products, US, THUMS 

Long Beach Co., Occidental Elk Hills, Inc., and Valero Refining Co.—California). 

CAISO ................................................................................ California Independent System Operator Corporation. 

California Commission ....................................................... Public Utilities Commission of the State of California. 

Calpine ............................................................................... Calpine Corporation. 

Chandley-Hogan ................................................................ John D. Chandley and William W. Hogan. 


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INITIAL COMMENTERS—Continued 

Abbreviation Initial commenters 

ColumbiaGrid ..................................................................... ColumbiaGrid Members (Bonneville Power Administration; Avista Corp.; Public Utility 

District No. 1 of Chelan County, Washington; Public Utility District No. 2 of Grant 

County, Washington; Puget Sound Energy, Inc.; Seattle City Light; and Tacoma 

Power. 

Community Power Alliance ................................................ Community Power Alliance Members (Entergy, Progress Energy, Salt River Project 

Agricultural Improvement and Power District, and Southern Co.). 

Constellation ....................................................................... Constellation Energy Group, Inc. 

CREPC ............................................................................... Committee on Regional Electric Power Corp. 

Dominion ............................................................................ Dominion Resources Services, Inc. (Armstrong Energy Limited Partnership, LLLP; 

Dominion Energy Marketing, Inc.; Elwood Energy, LLC; Fairless Energy, LLC; 

Pleasants Energy, LLC and Virginia Electric and Power Co. d/b/a Dominion Virginia Power). 

Dow .................................................................................... Dow Chemical Corp. 

Duke ................................................................................... Duke Energy Corp. 

E.ON ................................................................................... E.ON U.S. LLC. 

East Texas Cooperatives ................................................... East Texas Electric Cooperative, Inc.; Northeast Texas Electric Cooperative, Inc.; 

Sam Rayburn Generation and Electric Cooperative, Inc. and Tex-La Electric Cooperative of Texas, Inc. 

Eastern North Carolina ...................................................... Eastern NC Towns (Towns of Black Creek, NC; Lucama, NC; Stantonsburg, NC). 

EEI ...................................................................................... Edison Electric Institute. 

ELCON ............................................................................... Electricity Consumers Resource Council, American Iron and Steel Institute, and 

American Forest & Paper Institute. 

Emerald .............................................................................. Emerald People’s Utility District. 

Entegra ............................................................................... Entegra Power Group LLC and LS Power Associates, L.P. 

Entergy ............................................................................... Entergy Services, Inc. 

EPSA .................................................................................. Electric Power Supply Association. 

Exelon ................................................................................ Exelon Corporation. 

Fayetteville ......................................................................... Public Works Commission of the City of Fayetteville, North Carolina. 

Fertilizer Institute ................................................................ Fertilizer Institute. 

FirstEnergy ......................................................................... FirstEnergy Service Company (First Energy Solutions; American Transmission Systems, Inc.; Jersey Central Power and Light Co.; Metropolitan Edison Co.; and 

Pennsylvania Electric Co.). 

Flathead ............................................................................. Flathead Electric Cooperative. 

Florida Commission ........................................................... Florida Public Service Commission. 

Florida Industrial Cogeneration Association ...................... Florida Industrial Cogeneration Association. 

FMPA ................................................................................. Florida Municipal Power Agency and Midwest Municipal Transmission Group. 

Geothermal Producers ....................................................... CE Generation, LLC; Ormat Technologies, Inc.; Caithness Energy, LLC; and Geothermal Energy Association. 

Grant .................................................................................. Grant County PUD, Chelan County PUD and Pend Oreille County PUD. 

Great Northern ................................................................... Great Northern Power Development, L.P. 

Imperial ............................................................................... Imperial Irrigation District. 

Indianapolis Power ............................................................. Indianapolis Power & Light Co. 

Indicated New York Transmission Owners ........................ Central Hudson Gas & Electric Corp.; Consolidated Edison Co. of New York, Inc.; 

LIPA; New York Power Authority; New York State Electric & Gas Corp.; Orange 

and Rockland Utilities, Inc.; and Rochester Gas and Electric Corp. 

International Transmission ................................................. International Transmission Co. d/b/a ITCTransmission and Michigan Electric Transmission Co., LLC. 

IRH Management ............................................................... IRH Management Committee and the Schedule 20A Service Providers. 

ISO New England .............................................................. ISO New England, Inc. and New England Power Pool. 

ISO/RTO Council ............................................................... ISO/RTO Council. 

Lassen ................................................................................ Lassen Municipal Utility District. 

LDWP ................................................................................. City of Los Angeles Department of Water and Power. 

LPPC .................................................................................. Large Public Power Council. 

Manitoba Hydro .................................................................. Manitoba Hydro. 

MDEA ................................................................................. Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, and Public 

Service Commission of Yazoo City. 

MidAmerican ...................................................................... MidAmerican Energy Company and PacifiCorp. 

MISO .................................................................................. Midwest Independent Transmission System Operator, Inc. 

MISO Transmission Owners .............................................. Midwest ISO Transmission Owners. 

MISO/PJM States ............................................................... Organization of MISO States and Organization of PJM States, Inc. 

Morgan Stanley .................................................................. Morgan Stanley Capital Group Inc. 

NAESB ............................................................................... North American Energy Standards Board. 

NARUC ............................................................................... National Association of Regulatory Utility Commissioners. 

National Grid ...................................................................... National Grid USA. 

NCEMC .............................................................................. North Carolina Electric Membership Corporation. 

NCPA ................................................................................. Northern California Power Agency. 

NERC ................................................................................. North American Electric Reliability Corporation. 

Nevada Commission .......................................................... Public Utilities Commission of Nevada. 

Nevada Companies ............................................................ Nevada Power Company and Sierra Pacific Power Company. 

New Jersey Board .............................................................. New Jersey Board of Public Utilities. 

New Mexico Attorney General ........................................... New Mexico Attorney General. 

New York Commission ....................................................... New York State Public Service Commission. 


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INITIAL COMMENTERS—Continued 

Abbreviation Initial commenters 

Newfoundland .................................................................... Newfoundland and Labrador Hydro. 

Newmont Mining ................................................................ Newmont USA Limited, dba Newmont Mining Corp. 

Northeast Utilities ............................................................... Northeast Utilities Service Company (Connecticut Light and Power Co.; Western 

Massachusetts Electric Co.; Public Service Co. of New Hampshire; Holyoke Water 

Power Co.; and Holyoke Power and Electric Co.). 

Northwest IOUs .................................................................. Northwest Investor-Owned Utilities (Avista Corp., Portland General Electric Co., and 

Puget Sound Energy, Inc.). 

Northwest Parties ............................................................... Northwest Parties (Avista Corp., Bonneville Power Administration, PacifiCorp, PNGC 

Power, Portland General Electric Co., Public Power Council, Public Utility Commission of Oregon and Puget Sound Energy, Inc.). 

NorthWestern ..................................................................... NorthWestern Corporation. 

NPPD ................................................................................. Nebraska Public Power District. 

NRECA ............................................................................... National Rural Electric Cooperative Association. 

NRG ................................................................................... NRG Energy, Inc. 

NYAPP ............................................................................... New York Association of Public Power. 

Occidental .......................................................................... Occidental Chemical Corporation. 

Oklahoma Commission ...................................................... Oklahoma Corporation Commission. 

Old Dominion ..................................................................... Old Dominion Electric Cooperative. 

Oversight Resources .......................................................... Oversight Resources, LLC. 

PGP .................................................................................... Public Generating Pool and Chelan County PUD. 

Pinnacle .............................................................................. Pinnacle West Capital Corporation; Arizona Public Service Company; and APS Energy Services Company, Inc. 

PJM .................................................................................... PJM Interconnection, LLC. 

PNM–TNMP ....................................................................... Public Service Company of New Mexico and Texas-New Mexico Power Company. 

Powerex ............................................................................. Powerex Corp. 

PPL ..................................................................................... PPL Companies. 

PPM .................................................................................... PPM Energy, Inc. 

Progress Energy ................................................................ Progress Energy, Inc. (Carolina Power & Light Co. d/b/a Progress Energy Carolinas 

and Florida Power Corp., d/b/a Progress Energy Florida; and Progress Ventures, 

Inc.). 

Project for Sustainable FERC Energy Policy .................... Project for Sustainable FERC Energy Policy (American Wind Energy Association, 

Delaware Division of the Public Advocate, Environmental Law & Policy Center, Illinois Citizens Utility Board, Natural Resources Defense Council, Northwest Energy 

Coalition, Office of the Ohio Consumers’ Counsel, Pace Energy Project, Project for 

Sustainable FERC Energy Policy, Renewable Northwest Project, West Wind 

Wires, and Wind on the Wires). 

PSEG ................................................................................. Public Service Electric and Gas Company; PSEG Power LLC; and PSEC Energy Resources & Trade LLC (PSEG Companies). 

Public Power Council ......................................................... Public Power Council. 

Reliant ................................................................................ Reliant Energy, Inc. 

Sacramento ........................................................................ Sacramento Municipal Utility District. 

Salt River ............................................................................ Salt River Project Agricultural Improvement and Power District. 

San Diego G&E .................................................................. San Diego Gas & Electric Company. 

Santa Clara ........................................................................ City of Santa Clara, California d/b/a Silicon Valley Power. 

Santee Cooper ................................................................... South Carolina Public Service Authority. 

SCE .................................................................................... Southern California Edison. 

Seattle ................................................................................ City of Seattle—City Light Department. 

Sempra Global ................................................................... Sempra Global. 

South Carolina E&G ........................................................... South Carolina Electric & Gas Company. 

South Carolina Regulatory Staff ........................................ South Carolina Office of Regulatory Staff. 

Southern ............................................................................. Southern Company Services, Inc. 

Southwest Transmission .................................................... Southwest Area Transmission Sub-Regional Planning Group. 

Southwestern Coop ............................................................ Southwestern Electric Cooperative, Inc. 

SPP .................................................................................... Southwest Power Pool, Inc. 

Steel Manufacturers Association ....................................... Steel Manufacturers Association. 

Suez Energy NA ................................................................ Suez Energy North America, Inc. 

Tacoma .............................................................................. Tacoma Power. 

TANC .................................................................................. Transmission Agency of Northern California. 

TAPS .................................................................................. Transmission Access Policy Study Group. 

TDU Systems ..................................................................... Transmission Dependent Utilities Systems. 

TransAlta ............................................................................ TransAlta Energy Marketing (US) Inc. 

TranServ ............................................................................. TranServ International, Inc. 

Tucson ................................................................................ Tucson Electric Power Company. 

TVA .................................................................................... Tennessee Valley Authority. 

Utah Municipals .................................................................. Utah Associated Municipal Power Systems. 

WAPA ................................................................................. Western Area Power Administration. 

WECC ................................................................................ Western Electricity Coordinating Council. 

WestConnect ...................................................................... WestConnect Companies. 

Western Governors ............................................................ Western Governors’ Association. 

Williams .............................................................................. Williams Power Company, Inc. 

Wisconsin Electric .............................................................. Wisconsin Electric Power Company. 

WSPP ................................................................................. Western Systems Power Pool, Inc. 


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INITIAL COMMENTERS—Continued 

Abbreviation Initial commenters 

Xcel .................................................................................... Xcel Energy Services, Inc. 

REPLY COMMENTERS

Abbreviation Reply commenters 

Alberta Intervenors ............................................................. Alberta Intervenors (TransCanada Energy Ltd., ENMAX Energy Marketing, Inc.; 

EPCOR Merchant and Capital, LP; and TransAlta Corporation). 

Anaheim ............................................................................. Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California. 

APPA .................................................................................. American Public Power Association. 

Barrick ................................................................................ Barrick Goldstrike Mines Inc. 

Bonneville ........................................................................... Bonneville Power Administration. 

CAISO ................................................................................ California Independent System Operator Corporation. 

California Commission ....................................................... Public Utilities Commission of the State of California. 

Canadian Electricity Association ........................................ Canadian Electricity Association. 

Chandley-Hogan ................................................................ John D. Chandley and William W. Hogan. 

CMUA ................................................................................. California Municipal Utilities Association. 

ColumbiaGrid ..................................................................... ColumbiaGrid Members (Bonneville Power Administration; Avista Corp.; Public Utility 

District No. 1 of Chelan County, Washington; Public Utility District No. 2 of Grant 

County, Washington; Puget Sound Energy, Inc.; Seattle City Light; and Tacoma 

Power. 

Community Power Alliance ................................................ Community Power Alliance Members (Entergy, Progress Energy, Salt River Project 

Agricultural Improvement and Power District, and Southern Co.). 

Detroit Edison ..................................................................... Detroit Edison Co. 

Duke ................................................................................... Duke Energy Corp. 

Dynegy ............................................................................... Dynegy Power Marketing, Inc. 

East Texas Cooperatives ................................................... East Texas Electric Cooperative, Inc.; Northeast Texas Electric Cooperative, Inc.; 

Sam Rayburn Generation and Electric Cooperative, Inc. and Tex-La Electric Cooperative of Texas, Inc. 

EEI ...................................................................................... Edison Electric Institute. 

ElectriCities ........................................................................ ElectriCities of North Carolina, Inc. 

Entegra ............................................................................... Entegra Power Group LLC and LS Power Associates, L.P. 

Entergy ............................................................................... Entergy Services, Inc. 

EPSA .................................................................................. Electric Power Supply Association. 

Exelon ................................................................................ Exelon Corporation. 

Fayetteville ......................................................................... Public Works Commission of the City of Fayetteville, North Carolina. 

Fertilizer Institute ................................................................ Fertilizer Institute. 

FMPA ................................................................................. Florida Municipal Power Agency and Midwest Municipal Transmission Group. 

Great Northern ................................................................... Great Northern Power Development, L.P. 

Hoosier ............................................................................... Hoosier Energy Rural Electric Cooperative, Inc. 

H.Q. Energy ....................................................................... H.Q. Energy Services (U.S.), Inc. 

Indianapolis Power ............................................................. Indianapolis Power & Light Co. 

Industrial Customers of Northwest Utilities ........................ Industrial Customers of Northwest Utilities (Air Liquide; Air Products; BPB Gypsum, 

Inc.; Blue Heron Paper Company; Boeing; Boise Cascade; CNC Containers, 

Northwest; Chemi-Con Materials Corporation; Dyno Nobel, Inc.; ConAgra Foods; 

Eka Chemicals, Inc.; Evanite Fiber; Georgia-Pacific; Grays Harbor Paper, L.P.; 

Hewlett-Packard; Inland Empire Paper Co.; Intel; J.R. Simplot; Kimberly-Clark Corporation; Longview Fibre; Microsoft Corporation; Norpac Foods; Noveon Kalama, 

Inc.; Oregon Steel Mills; PCC Structurals, Inc.; Ponderay Newsprint Co; Shell Oil 

Products US; Simpson Paper; Simpson Timber; Solar Grade Silicon LLC; SP 

Newsprint Co.; Tesoro Refining and Marketing Co.; Wah Chang; West Linn Paper 

Company; Weyerhaeuser). 

International Transmission ................................................. International Transmission Co. d/b/a ITCTransmission and Michigan Electric Transmission Co., LLC. 

ISO/RTO Council ............................................................... ISO/RTO Council. 

Lassen ................................................................................ Lassen Municipal Utility District. 

LPPC .................................................................................. Large Public Power Council. 

MAPP ................................................................................. Mid-Continent Area Power Pool. 

Mark Lively ......................................................................... Mark B. Lively. 

MDEA ................................................................................. Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public 

Service Commission of Yazoo City, Arkansas Electric Cooperative Corporation, 

Municipal Energy Agency of Mississippi, and Lafayette Utilities System*.1008

MidAmerican ...................................................................... MidAmerican Energy Company and PacifiCorp. 

MISO .................................................................................. Midwest Independent Transmission System Operator, Inc. 

Morgan Stanley .................................................................. Morgan Stanley Capital Group Inc. 

NARUC ............................................................................... National Association of Regulatory Utility Commissioners. 

NC Transmission Planning Participants ............................ North Carolina Transmission Planning Collaborative Participants. 

NCPA ................................................................................. Northern California Power Agency. 

Newmont Mining ................................................................ Newmont USA Limited, dba Newmont Mining Corp. 

North Carolina Commission ............................................... North Carolina Utilities Commission; Public Staff of the North Carolina Utilities Commission; and the Attorney General of the State of North Carolina. 


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REPLY COMMENTERS—Continued 

Abbreviation Reply commenters 

Northwest IOUs .................................................................. Northwest Investor-Owned Utilities (Avista Corp., Portland General Electric Co., and 

Puget Sound Energy, Inc.). 

NorthWestern ..................................................................... NorthWestern Corporation. 

NRECA ............................................................................... National Rural Electric Cooperative Association. 

Occidental .......................................................................... Occidental Chemical Corporation. 

OG&E ................................................................................. Oklahoma Gas and Electric Company. 

Ohio Power Siting Board ................................................... Ohio Power Siting Board, American Municipal Power-Ohio, Inc. and Buckeye Power, 

Inc. 

Old Dominion ..................................................................... Old Dominion Electric Cooperative; Southern Maryland Electric Cooperative, Inc.; Allegheny Electric Cooperative, Inc.; and North Carolina Electric Membership Corporation. 

Omaha Public Power ......................................................... Omaha Public Power District. 

Pennsylvania Commission ................................................. Pennsylvania Public Utility Commission. 

PJM .................................................................................... PJM Interconnection, LLC. 

PNM-TNMP ........................................................................ Public Service Company of New Mexico and Texas-New Mexico Power Company. 

Powerex ............................................................................. Powerex Corp. 

PPM .................................................................................... PPM Energy, Inc. 

Progress Energy ................................................................ Progress Energy, Inc. (Carolina Power & Light Co. d/b/a Progress Energy Carolinas 

and Florida Power Corp., d/b/a Progress Energy Florida; and Progress Ventures, 

Inc.). 

Project for Sustainable FERC Energy Policy .................... Project for Sustainable FERC Energy Policy (Delaware Division of the Public Advocate, Environmental Law & Policy Center, Fresh Energy, Natural Resources Defense Council, Northwest Energy Coalition, Pace Energy Project, Project for Sustainable FERC Energy Policy, Renewable Northwest Project, West Wind Wires, 

and Wind on the Wires).* 

Public Power Council ......................................................... Public Power Council. 

Sacramento ........................................................................ Sacramento Municipal Utility District. 

Salt River ............................................................................ Salt River Project Agricultural Improvement and Power District. 

Santa Clara ........................................................................ City of Santa Clara, California d/b/a Silicon Valley Power. 

Seattle ................................................................................ City of Seattle—City Light Department. 

Seminole ............................................................................ Seminole Electric Cooperative, Inc. 

South Carolina E&G ........................................................... South Carolina Electric & Gas Company. 

Southern ............................................................................. Southern Company Services, Inc. 

SPP .................................................................................... Southwest Power Pool, Inc. 

Steel Manufacturers Association ....................................... Steel Manufacturers Association. 

Strategic Energy ................................................................. Strategic Energy, L.L.C. 

TANC .................................................................................. Transmission Agency of Northern California. 

TAPS .................................................................................. Transmission Access Policy Study Group. 

TDU Systems ..................................................................... Transmission Dependent Utilities Systems. 

Transparent Dispatch Advocates ....................................... PJM Interconnection, LLC; Electric Consumers Resource Council; Electric Power 

Supply Association; Natural Resources Defense Council; Renewable Northwest 

Project; Project for Sustainable FERC Energy Policy; Center for Energy Efficiency 

& Renewable Technologies; Shell Trading Gas and Power Company; American 

Wind Energy Association; and Exelon. 

Utah Municipals .................................................................. Utah Associated Municipal Power Systems. 

WestConnect ...................................................................... WestConnect Companies. 

Williams .............................................................................. Williams Power Company, Inc. 

Wolverine ........................................................................... Wolverine Power Supply Cooperative, Inc. 

WPS Companies ................................................................ WPS Companies (Wisconsin Public Service Corporation and Upper Peninsula Power 

Company). 

WSPP ................................................................................. Western Systems Power Pool, Inc. 

Xcel .................................................................................... Xcel Energy Services, Inc. 

TECHNICAL CONFERENCE COMMENTERS

Abbreviation Technical conference commenters 

APPA* ................................................................................ American Public Power Association. 

APS* ................................................................................... Arizona Public Service Company. 

Bonneville* ......................................................................... Bonneville Power Administration. 

Constellation* ..................................................................... Constellation Energy Group, Inc. 

EEI* .................................................................................... Exelon Corporation on behalf of Edison Electric Institute (EEI). 

EPSA*1009 .......................................................................... Electric Power Supply Association. 

Exelon* ............................................................................... Exelon. 

NAESB* .............................................................................. North American Energy Standards Board. 

NARUC* ............................................................................. National Association of Regulatory Utility Commissioners. 

National Grid* ..................................................................... National Grid USA. 

National Grid/Central Hudson ............................................ National Grid USA, Central Hudson Gas & Electric Corporation, and American Wind 

Energy. 

NERC* ................................................................................ Prague Power, LLC, on behalf of the North American Electric Reliability Corporation. 


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TECHNICAL CONFERENCE COMMENTERS—Continued 

Abbreviation Technical conference commenters 

New York Parties ............................................................... Consolidated Edison Co. of New York, Inc., Orange and Rockland Utilities, Inc., New 

York Power Authority, and Independent Power Producers of New York, Inc. 

NRECA* ............................................................................. Great River Energy on behalf of National Rural Electric Cooperative Association 

(NRECA). 

NRG on behalf of EPSA* ................................................... NRG Energy, Inc. on behalf of Electric Power Supply Association (EPSA). 

PacifiCorp ........................................................................... PacifiCorp. 

PJM* ................................................................................... PJM Interconnection, LLC. 

AWEA* ............................................................................... PPM Energy, Inc. on behalf of American Wind Energy Association 

Progress Energy* ............................................................... Progress Energy, Inc. (Carolina Power & Light Company, d/b/a. Progress Energy 

Carolinas, Inc. and Florida Power Corporation, d/b/a Progress Energy Florida, 

Inc.). 

Renewable Northwest Project* .......................................... Renewable Northwest Project. 

San Diego G&E .................................................................. San Diego Gas & Electric Company. 

TAPS* ................................................................................. Southern Minnesota Municipal Power Agency and Transmission Access Policy Study 

Group. 

TDU Systems ..................................................................... Transmission Dependent Utilities Systems. 

South Carolina Regulatory Staff ........................................ South Carolina Office of Regulatory Staff. 

Southern* ........................................................................... Southern Company Services, Inc. 

WECC* ............................................................................... Western Electricity Coordinating Council. 

Williams* ............................................................................. Williams Power. 

Williams* ............................................................................. Williams Power Company, Inc. 

Xcel* ................................................................................... Xcel Energy Services, Inc. 

SUPPLEMENTAL COMMENTERS

Abbreviation Supplemental commenters 

Alabama Commission ........................................................ Alabama Public Service Commission. 

Ameren ............................................................................... Ameren Services Company. 

APPA .................................................................................. American Public Power Association. 

Barrick ................................................................................ Barrick Goldstrike Mines Inc. 

Bonneville ........................................................................... Bonneville Power Administration. 

BP Energy .......................................................................... BP Energy Company. 

California Commission ....................................................... Public Utilities Commission of the State of California. 

Community Power Alliance ................................................ Community Power Alliance Members (Entergy, Progress Energy, Salt River Project 

Agricultural Improvement and Power District, and Southern Co.). 

Constellation ....................................................................... Constellation Energy Group, Inc. 

Duke ................................................................................... Duke Energy Corp. 

E.ON ................................................................................... E.ON U.S. LLC. 

EEI ...................................................................................... Edison Electric Institute. 

Entergy ............................................................................... Entergy Services, Inc. 

EPSA and AWEA ............................................................... Electric Power Supply Association and American Wind Energy Association. 

Florida Commission ........................................................... Florida Public Service Commission. 

Georgia Commission .......................................................... Georgia Public Service Commission. 

LPPC .................................................................................. Large Public Power Council. 

Mark Lively ......................................................................... Mark B. Lively. 

MISO .................................................................................. Midwest Independent Transmission System Operator, Inc. 

Nevada Companies ............................................................ Nevada Power Company and Sierra Pacific Power Company. 

North Carolina Commission ............................................... North Carolina Utilities Commission; Public Staff of the North Carolina Utilities Commission; and the Attorney General of the State of North Carolina. 

NRECA ............................................................................... National Rural Electric Cooperative Association. 

OG&E ................................................................................. Oklahoma Gas and Electric Company. 

Pacific Coast Parties .......................................................... Pacific Coast Parties (Avista Corporation, Bonneville Power Administration, 

PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc., the 

Sacramento Municipal Utility District and the Transmission Agency of Northern 

California). 

PGP .................................................................................... Public Generating Pool. 

Southwest Utilities .............................................................. Pinnacle West Companies, Public Service Company of New Mexico, Texas-New 

Mexico Power Company, and UniSource Energy Corporation. 

PNM-TNMP ........................................................................ Public Service Company of New Mexico and Texas-New Mexico Power Company. 

Powerex ............................................................................. Powerex Corp. 

PPL ..................................................................................... PPL Companies. 

PPM .................................................................................... PPM Energy, Inc. 

Progress Energy ................................................................ Progress Energy, Inc. (Carolina Power & Light Company, d/b/a. Progress Energy 

Carolinas, Inc. and Florida Power Corporation, d/b/a Progress Energy Florida, 

Inc.). 

Progress Energy and MidAmerican ................................... Progress Energy, Inc. and MidAmerican Energy Company. 

Public Power Council ......................................................... Public Power Council. 

SEARUC ............................................................................ Southeastern Association of Regulatory Utility Commissioners. 

South Carolina E&G ........................................................... South Carolina Electric & Gas Company. 

South Carolina Regulatory Staff ........................................ South Carolina Office of Regulatory Staff. 


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1008A ‘‘*’’ indicates that the composition of this 

group has altered in the reply comment filing. 

1009A ‘‘*’’ indicates that this party submitted 

speaker materials at the October 12 Technical 

Conference. 

1010A ‘‘*’’ indicates that the composition of this 

group has altered in this filing. 

SUPPLEMENTAL COMMENTERS—Continued 

Abbreviation Supplemental commenters 

Southern ............................................................................. Southern Company Services, Inc. 

Tacoma .............................................................................. Tacoma Power. 

TAPS .................................................................................. Transmission Access Policy Study Group. 

TDU Systems ..................................................................... Transmission Dependent Utilities Systems. 

Transparent Dispatch Advocates ....................................... Transparent Dispatch Advocates (American Wind Energy Association; Center for Energy Efficiency & Renewable Technologies; Electric Consumers Resource Council; 

Electric Power Supply Association; Exelon Corporation; Natural Resources Defense Council; PJM Interconnection, LLC; PPM Energy; Project for Sustainable 

FERC Energy Policy; Renewable Northwest Project; and Shell Trading Gas and 

Power Company)*1010

Western Governors ............................................................ Western Governors’ Association. 

Williams .............................................................................. Williams Power Company, Inc. 

WIRES ................................................................................ WIRES. 

Xcel .................................................................................... Xcel Energy Services, Inc. 

Appendix C: Pro Forma Open Access 

Transmission Tariff 

Table of Contents 

I. Common Service Provisions 

1 Definitions 

1.1 Affiliate 

1.2 Ancillary Services 

1.3 Annual Transmission Costs 

1.4 Application 

1.5 Commission 

1.6 Completed Application 

1.7 Control Area 

1.8 Curtailment 

1.9 Delivering Party 

1.10 Designated Agent 

1.11 Direct Assignment Facilities 

1.12 Eligible Customer 

1.13 Facilities Study 

1.14 Firm Point-To-Point Transmission 

Service 

1.15 Good Utility Practice 

1.16 Interruption 

1.17 Load Ratio Share 

1.18 Load Shedding 

1.19 Long-Term Firm Point-To-Point 

Transmission Service 

1.20 Native Load Customers 

1.21 Network Customer 

1.22 Network Integration Transmission 

Service 

1.23 Network Load 

1.24 Network Operating Agreement 

1.25 Network Operating Committee 

1.26 Network Resource 

1.27 Network Upgrades 

1.28 Non-Firm Point-To-Point 

Transmission Service 

1.29 Non-Firm Sale 

1.30 Open Access Same-Time 

Information System (OASIS) 

1.31 Part I 

1.32 Part II 

1.33 Part III 

1.34 Parties 

1.35 Point(s) of Delivery 

1.36 Point(s) of Receipt 

1.37 Point-To-Point Transmission Service 

1.38 Power Purchaser 

1.39 Pre-Confirmed Application 

1.40 Receiving Party 

1.41 Regional Transmission Group (RTG) 

1.42 Reserved Capacity 

1.43 Service Agreement 

1.44 Service Commencement Date 

1.45 Short-Term Firm Point-To-Point 

Transmission Service 

1.46 System Condition 

1.47 System Impact Study 

1.48 Third-Party Sale 

1.49 Transmission Customer 

1.50 Transmission Provider 

1.51 Transmission Provider’s Monthly 

Transmission System Peak 

1.52 Transmission Service 

1.53 Transmission System 

2 Initial Allocation and Renewal 

Procedures 

2.1 Initial Allocation of Available 

Transfer Capability 

2.2 Reservation Priority for Existing Firm 

Service Customers 

3 Ancillary Services 

3.1 Scheduling, System Control and 

Dispatch Service 

3.2 Reactive Supply and Voltage Control 

From Generation or Other Sources 

Service 

3.3 Regulation and Frequency Response 

Service 

3.4 Energy Imbalance Service 

3.5 Operating Reserve—Spinning Reserve 

Service 

3.6 Operating Reserve—Supplemental 

Reserve Service 

3.7 Generator Imbalance Service 

4 Open Access Same-Time Information 

System (OASIS) 

5 Local Furnishing Bonds 

5.1 Transmission Providers That Own 

Facilities Financed by Local Furnishing 

Bonds 

5.2 Alternative Procedures for Requesting 

Transmission Service 

6 Reciprocity 

7 Billing and Payment 

7.1 Billing Procedure: 

7.2 Interest on Unpaid Balances 

7.3 Customer Default 

8 Accounting for the Transmission 

Provider’s Use of the Tariff 

8.1 Transmission Revenues 

8.2 Study Costs and Revenues 

9 Regulatory Filings 

10 Force Majeure and Indemnification 

10.1 Force Majeure 

10.2 Indemnification 

11 Creditworthiness 

12 Dispute Resolution Procedures 

12.1 Internal Dispute Resolution 

Procedures 

12.2 External Arbitration Procedures 

12.3 Arbitration Decisions 

12.4 Costs 

12.5 Rights Under the Federal Power Act 

II. Point-to-Point Transmission Service 

13 Nature of Firm Point-to-Point 

Transmission Service 

13.1 Term 

13.2 Reservation Priority 

13.3 Use of Firm Transmission Service by 

the Transmission Provider 

13.4 Service Agreements 

13.5 Transmission Customer Obligations 

for Facility Additions or Redispatch 

Costs 

13.6 Curtailment of Firm Transmission 

Service 

13.7 Classification of Firm Transmission 

Service 

13.8 Scheduling of Firm Point-To-Point 

Transmission Service 

14 Nature of Non-Firm Point-to-Point 

Transmission Service 

14.1 Term 

14.2 Reservation Priority 

14.3 Use of Non-Firm Point-To-Point 

Transmission Service by the 

Transmission Provider 

14.4 Service Agreements 

14.5 Classification of Non-Firm Point-ToPoint Transmission Service 

14.6 Scheduling of Non-Firm Point-ToPoint Transmission Service 

14.7 Curtailment or Interruption of 

Service 

15 Service Availability 

15.1 General Conditions 

15.2 Determination of Available Transfer 

Capability 

15.3 Initiating Service in the Absence of 

an Executed Service Agreement 

15.4 Obligation to Provide Transmission 

Service that Requires Expansion or 

Modification of the Transmission 

System, Redispatch or Conditional 

Curtailment 


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15.5 Deferral of Service 

15.6 Other Transmission Service 

Schedules 

15.7 Real Power Losses 

16 Transmission Customer 

Responsibilities 

16.1 Conditions Required of 

Transmission Customers 

16.2 Transmission Customer 

Responsibility for Third-Party 

Arrangements 

17 Procedures For Arranging Firm Pointto-Point Transmission Service 

17.1 Application 

17.2 Completed Application 

17.3 Deposit 

17.4 Notice of Deficient Application 

17.5 Response to a Completed 

Application 

17.6 Execution of Service Agreement 

17.7 Extensions for Commencement of 

Service 

18 Procedures for Arranging Non-Firm 

Point-to-Point Transmission Service 

18.1 Application 

18.2 Completed Application 

18.3 Reservation of Non-Firm Point-toPoint Transmission Service 

18.4 Determination of Available Transfer 

Capability 

19 Additional Study Procedures For Firm 

Point-to-Point Transmission Service 

Requests 

19.1 Notice of Need for System Impact 

Study 

19.2 System Impact Study Agreement and 

Cost Reimbursement 

19.3 System Impact Study Procedures 

19.4 Facilities Study Procedures 

19.5 Facilities Study Modifications 

19.6 Due Diligence in Completing New 

Facilities 

19.7 Partial Interim Service 

19.8 Expedited Procedures for New 

Facilities 

19.9 Penalties for Failure to Meet Study 

Deadlines 

20 Procedures if the Transmission 

Provider is Unable to Complete New 

Transmission Facilities for Firm Pointto-Point Transmission Service 

20.1 Delays in Construction of New 

Facilities: 

20.2 Alternatives to the Original Facility 

Additions 

20.3 Refund Obligation for Unfinished 

Facility Additions 

21 Provisions Relating to Transmission 

Construction and Services on the 

Systems of Other Utilities 

21.1 Responsibility for Third-Party 

System Additions 

21.2 Coordination of Third-Party System 

Additions 

22 Changes in Service Specifications 

22.1 Modifications On a Non-Firm Basis 

22.2 Modification On a Firm Basis 

23 Sale or Assignment of Transmission 

Service 

23.1 Procedures for Assignment or 

Transfer of Service 

23.2 Limitations on Assignment or 

Transfer of Service 

23.3 Information on Assignment or 

Transfer of Service 

24 Metering and Power Factor Correction 

at Receipt and Delivery Points(s) 

24.1 Transmission Customer Obligations 

24.2 Transmission Provider Access to 

Metering Data 

24.3 Power Factor 

25 Compensation for Transmission 

Service 

26 Stranded Cost Recovery 

27 Compensation for New Facilities and 

Redispatch Costs 

III. Network Integration Transmission Service 

28 Nature of Network Integration 

Transmission Service 

28.1 Scope of Service 

28.2 Transmission Provider 

Responsibilities 

28.3 Network Integration Transmission 

Service 

28.4 Secondary Service 

28.5 Real Power Losses 

28.6 Restrictions on Use of Service 

29 Initiating Service 

29.1 Condition Precedent for Receiving 

Service 

29.2 Application Procedures 

29.3 Technical Arrangements to be 

Completed Prior to Commencement of 

Service 

29.4 Network Customer Facilities 

29.5 Filing of Service Agreement 

30 Network Resources 

30.1 Designation of Network Resources 

30.2 Designation of New Network 

Resources 

30.3 Termination of Network Resources 

30.4 Operation of Network Resources 

30.5 Network Customer Redispatch 

Obligation 

30.6 Transmission Arrangements for 

Network Resources Not Physically 

Interconnected With the Transmission 

Provider 

30.7 Limitation on Designation of 

Network Resources 

30.8 Use of Interface Capacity by the 

Network Customer 

30.9 Network Customer Owned 

Transmission Facilities 

31 Designation of Network Load 

31.1 Network Load 

31.2 New Network Loads Connected With 

the Transmission Provider 

31.3 Network Load Not Physically 

Interconnected With the Transmission 

Provider 

31.4 New Interconnection Points 

31.5 Changes in Service Requests 

31.6 Annual Load and Resource 

Information Updates 

32 Additional Study Procedures for 

Network Integration Transmission 

Service Requests 

32.1 Notice of Need for System Impact 

Study 

32.2 System Impact Study Agreement and 

Cost Reimbursement 

32.3 System Impact Study Procedures 

32.4 Facilities Study Procedures 

32.5 Penalties for Failure to Meet Study 

Deadlines 

33 Load Shedding and Curtailments 

33.1 Procedures 

33.2 Transmission Constraints 

33.3 Cost Responsibility for Relieving 

Transmission Constraints 

33.4 Curtailments of Scheduled 

Deliveries 

33.5 Allocation of Curtailments 

33.6 Load Shedding 

33.7 System Reliability 

34 Rates and Charges 

34.1 Monthly Demand Charge 

34.2 Determination of Network 

Customer’s Monthly Network Load 

34.3 Determination of Transmission 

Provider’s Monthly Transmission System 

Load 

34.4 Redispatch Charge 

34.5 Stranded Cost Recovery 

35 Operating Arrangements 

35.1 Operation Under The Network 

Operating Agreement 

35.2 Network Operating Agreement 

35.3 Network Operating Committee 

Schedule 1 

Scheduling, System Control and Dispatch 

Service 

Schedule 2 

Reactive Supply and Voltage Control From 

Generation Sources Service 

Schedule 3 

Regulation and Frequency Response 

Service 

Schedule 4 

Energy Imbalance Service 

Schedule 5 

Operating Reserve—Spinning Reserve 

Service 

Schedule 6 

Operating Reserve—Supplemental Reserve 

Service 

Schedule 7 

Long-Term Firm and Short-Term Firm 

Point-to-Point 

Schedule 8 

Non-Firm Point-to-Point Transmission 

Service 

Schedule 9 

Generator Imbalance Service 

Attachment A 

Form of Service Agreement for Firm Pointto-Point Transmission Service 

Attachment A–1 

Form of Service Agreement for the Resale, 

Reassignment or Transfer of Long-Term 

Firm Point-to-Point Transmission 

Service 

Attachment B 

Form of Service Agreement for Non-Firm 

Point-to-Point Transmission Service 

Attachment C 

Methodology to Assess Available Transfer 

Capability 

Attachment D 

Methodology for Completing a System 

Impact Study 

Attachment E 

Index of Point-to-Point Transmission 

Service Customers 

Attachment F 

Service Agreement for Network Integration 

Transmission Service 


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Attachment G 

Network Operating Agreement 

Attachment H 

Annual Transmission Revenue 

Requirement for Network Integration 

Transmission Service 

Attachment I 

Index of Network Integration Transmission 

Service Customers 

Attachment J 

Procedures for Addressing Parallel Flows 

Attachment K 

Transmission Planning Process 

Attachment L 

Creditworthiness Procedures 

I. Common Service Provisions 

1 Definitions 

1.1 Affiliate 

With respect to a corporation, 

partnership or other entity, each such 

other corporation, partnership or other 

entity that directly or indirectly, 

through one or more intermediaries, 

controls, is controlled by, or is under 

common control with, such corporation, 

partnership or other entity. 

1.2 Ancillary Services 

Those services that are necessary to 

support the transmission of capacity 

and energy from resources to loads 

while maintaining reliable operation of 

the Transmission Provider’s 

Transmission System in accordance 

with Good Utility Practice. 

1.3 Annual Transmission Costs 

The total annual cost of the 

Transmission System for purposes of 

Network Integration Transmission 

Service shall be the amount specified in 

Attachment H until amended by the 

Transmission Provider or modified by 

the Commission. 

1.4 Application 

A request by an Eligible Customer for 

transmission service pursuant to the 

provisions of the Tariff. 

1.5 Commission 

The Federal Energy Regulatory 

Commission. 

1.6 Completed Application 

An Application that satisfies all of the 

information and other requirements of 

the Tariff, including any required 

deposit. 

1.7 Control Area 

An electric power system or 

combination of electric power systems 

to which a common automatic 

generation control scheme is applied in 

order to: 

1. Match, at all times, the power 

output of the generators within the 

electric power system(s) and capacity 

and energy purchased from entities 

outside the electric power system(s), 

with the load within the electric power 

system(s); 

2. Maintain scheduled interchange 

with other Control Areas, within the 

limits of Good Utility Practice; 

3. Maintain the frequency of the 

electric power system(s) within 

reasonable limits in accordance with 

Good Utility Practice; and 

4. Provide sufficient generating 

capacity to maintain operating reserves 

in accordance with Good Utility 

Practice. 

1.8 Curtailment 

A reduction in firm or non-firm 

transmission service in response to a 

transfer capability shortage as a result of 

system reliability conditions. 

1.9 Delivering Party 

The entity supplying capacity and 

energy to be transmitted at Point(s) of 

Receipt. 

1.10 Designated Agent 

Any entity that performs actions or 

functions on behalf of the Transmission 

Provider, an Eligible Customer, or the 

Transmission Customer required under 

the Tariff. 

1.11 Direct Assignment Facilities 

Facilities or portions of facilities that 

are constructed by the Transmission 

Provider for the sole use/benefit of a 

particular Transmission Customer 

requesting service under the Tariff. 

Direct Assignment Facilities shall be 

specified in the Service Agreement that 

governs service to the Transmission 

Customer and shall be subject to 

Commission approval. 

1.12 Eligible Customer 

i. Any electric utility (including the 

Transmission Provider and any power 

marketer), Federal power marketing 

agency, or any person generating 

electric energy for sale for resale is an 

Eligible Customer under the Tariff. 

Electric energy sold or produced by 

such entity may be electric energy 

produced in the United States, Canada 

or Mexico. However, with respect to 

transmission service that the 

Commission is prohibited from ordering 

by Section 212(h) of the Federal Power 

Act, such entity is eligible only if the 

service is provided pursuant to a state 

requirement that the Transmission 

Provider offer the unbundled 

transmission service, or pursuant to a 

voluntary offer of such service by the 

Transmission Provider. 

ii. Any retail customer taking 

unbundled transmission service 

pursuant to a state requirement that the 

Transmission Provider offer the 

transmission service, or pursuant to a 

voluntary offer of such service by the 

Transmission Provider, is an Eligible 

Customer under the Tariff. 

1.13 Facilities Study 

An engineering study conducted by 

the Transmission Provider to determine 

the required modifications to the 

Transmission Provider’s Transmission 

System, including the cost and 

scheduled completion date for such 

modifications, that will be required to 

provide the requested transmission 

service. 

1.14 Firm Point-To-Point 

Transmission Service 

Transmission Service under this 

Tariff that is reserved and/or scheduled 

between specified Points of Receipt and 

Delivery pursuant to Part II of this 

Tariff. 

1.15 Good Utility Practice 

Any of the practices, methods and 

acts engaged in or approved by a 

significant portion of the electric utility 

industry during the relevant time 

period, or any of the practices, methods 

and acts which, in the exercise of 

reasonable judgment in light of the facts 

known at the time the decision was 

made, could have been expected to 

accomplish the desired result at a 

reasonable cost consistent with good 

business practices, reliability, safety and 

expedition. Good Utility Practice is not 

intended to be limited to the optimum 

practice, method, or act to the exclusion 

of all others, but rather to be acceptable 

practices, methods, or acts generally 

accepted in the region, including those 

practices required by Federal Power Act 

section 215(a)(4). 

1.16 Interruption 

A reduction in non-firm transmission 

service due to economic reasons 

pursuant to Section 14.7. 

1.17 Load Ratio Share 

Ratio of a Transmission Customer’s 

Network Load to the Transmission 

Provider’s total load computed in 

accordance with Sections 34.2 and 34.3 

of the Network Integration Transmission 

Service under Part III of the Tariff and 

calculated on a rolling twelve month 

basis. 


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1.18 Load Shedding 

The systematic reduction of system 

demand by temporarily decreasing load 

in response to transmission system or 

area capacity shortages, system 

instability, or voltage control 

considerations under Part III of the 

Tariff. 

1.19 Long-Term Firm Point-To-Point 

Transmission Service 

Firm Point-To-Point Transmission 

Service under Part II of the Tariff with 

a term of one year or more. 

1.20 Native Load Customers 

The wholesale and retail power 

customers of the Transmission Provider 

on whose behalf the Transmission 

Provider, by statute, franchise, 

regulatory requirement, or contract, has 

undertaken an obligation to construct 

and operate the Transmission Provider’s 

system to meet the reliable electric 

needs of such customers. 

1.21 Network Customer 

An entity receiving transmission 

service pursuant to the terms of the 

Transmission Provider’s Network 

Integration Transmission Service under 

Part III of the Tariff. 

1.22 Network Integration Transmission 

Service 

The transmission service provided 

under Part III of the Tariff. 

1.23 Network Load 

The load that a Network Customer 

designates for Network Integration 

Transmission Service under Part III of 

the Tariff. The Network Customer’s 

Network Load shall include all load 

served by the output of any Network 

Resources designated by the Network 

Customer. A Network Customer may 

elect to designate less than its total load 

as Network Load but may not designate 

only part of the load at a discrete Point 

of Delivery. Where a Eligible Customer 

has elected not to designate a particular 

load at discrete points of delivery as 

Network Load, the Eligible Customer is 

responsible for making separate 

arrangements under Part II of the Tariff 

for any Point-To-Point Transmission 

Service that may be necessary for such 

non-designated load. 

1.24 Network Operating Agreement 

An executed agreement that contains 

the terms and conditions under which 

the Network Customer shall operate its 

facilities and the technical and 

operational matters associated with the 

implementation of Network Integration 

Transmission Service under Part III of 

the Tariff. 

1.25 Network Operating Committee 

A group made up of representatives 

from the Network Customer(s) and the 

Transmission Provider established to 

coordinate operating criteria and other 

technical considerations required for 

implementation of Network Integration 

Transmission Service under Part III of 

this Tariff. 

1.26 Network Resource 

Any designated generating resource 

owned, purchased or leased by a 

Network Customer under the Network 

Integration Transmission Service Tariff. 

Network Resources do not include any 

resource, or any portion thereof, that is 

committed for sale to third parties or 

otherwise cannot be called upon to meet 

the Network Customer’s Network Load 

on a non-interruptible basis. 

1.27 Network Upgrades 

Modifications or additions to 

transmission-related facilities that are 

integrated with and support the 

Transmission Provider’s overall 

Transmission System for the general 

benefit of all users of such Transmission 

System. 

1.28 Non-Firm Point-To-Point 

Transmission Service 

Point-To-Point Transmission Service 

under the Tariff that is reserved and 

scheduled on an as-available basis and 

is subject to Curtailment or Interruption 

as set forth in Section 14.7 under Part 

II of this Tariff. Non-Firm Point-ToPoint Transmission Service is available 

on a stand-alone basis for periods 

ranging from one hour to one month. 

1.29 Non-Firm Sale 

An energy sale for which receipt or 

delivery may be interrupted for any 

reason or no reason, without liability on 

the part of either the buyer or seller. 

1.30 Open Access Same-Time 

Information System (OASIS) 

The information system and standards 

of conduct contained in Part 37 of the 

Commission’s regulations and all 

additional requirements implemented 

by subsequent Commission orders 

dealing with OASIS. 

1.31 Part I 

Tariff Definitions and Common 

Service Provisions contained in 

Sections 2 through 12. 

1.32 Part II 

Tariff Sections 13 through 27 

pertaining to Point-To-Point 

Transmission Service in conjunction 

with the applicable Common Service 

Provisions of Part I and appropriate 

Schedules and Attachments. 

1.33 Part III 

Tariff Sections 28 through 35 

pertaining to Network Integration 

Transmission Service in conjunction 

with the applicable Common Service 

Provisions of Part I and appropriate 

Schedules and Attachments. 

1.34 Parties 

The Transmission Provider and the 

Transmission Customer receiving 

service under the Tariff. 

1.35 Point(s) of Delivery 

Point(s) on the Transmission 

Provider’s Transmission System where 

capacity and energy transmitted by the 

Transmission Provider will be made 

available to the Receiving Party under 

Part II of the Tariff. The Point(s) of 

Delivery shall be specified in the 

Service Agreement for Long-Term Firm 

Point-To-Point Transmission Service. 

1.36 Point(s) of Receipt 

Point(s) of interconnection on the 

Transmission Provider’s Transmission 

System where capacity and energy will 

be made available to the Transmission 

Provider by the Delivering Party under 

Part II of the Tariff. The Point(s) of 

Receipt shall be specified in the Service 

Agreement for Long-Term Firm PointTo-Point Transmission Service. 

1.37 Point-To-Point Transmission 

Service 

The reservation and transmission of 

capacity and energy on either a firm or 

non-firm basis from the Point(s) of 

Receipt to the Point(s) of Delivery under 

Part II of the Tariff. 

1.38 Power Purchaser 

The entity that is purchasing the 

capacity and energy to be transmitted 

under the Tariff. 

1.39 Pre-Confirmed Application 

An Application that commits the 

Transmission Customer to execute a 

Service Agreement upon receipt of 

notification that the Transmission 

Provider can provide the requested 

Transmission Service. 

1.40 Receiving Party 

The entity receiving the capacity and 

energy transmitted by the Transmission 

Provider to Point(s) of Delivery. 

1.41 Regional Transmission Group 

(RTG) 

A voluntary organization of 

transmission owners, transmission users 

and other entities approved by the 

Commission to efficiently coordinate 


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transmission planning (and expansion), 

operation and use on a regional (and 

interregional) basis. 

1.42 Reserved Capacity 

The maximum amount of capacity 

and energy that the Transmission 

Provider agrees to transmit for the 

Transmission Customer over the 

Transmission Provider’s Transmission 

System between the Point(s) of Receipt 

and the Point(s) of Delivery under Part 

II of the Tariff. Reserved Capacity shall 

be expressed in terms of whole 

megawatts on a sixty (60) minute 

interval (commencing on the clock 

hour) basis. 

1.43 Service Agreement 

The initial agreement and any 

amendments or supplements thereto 

entered into by the Transmission 

Customer and the Transmission 

Provider for service under the Tariff. 

1.44 Service Commencement Date 

The date the Transmission Provider 

begins to provide service pursuant to 

the terms of an executed Service 

Agreement, or the date the Transmission 

Provider begins to provide service in 

accordance with Section 15.3 or Section 

29.1 under the Tariff. 

1.45 Short-Term Firm Point-To-Point 

Transmission Service 

Firm Point-To-Point Transmission 

Service under Part II of the Tariff with 

a term of less than one year. 

1.46 System Condition 

A specified condition on the 

Transmission Provider’s system or on a 

neighboring system, such as a 

constrained transmission element or 

flowgate, that may trigger Curtailment of 

Long-Term Firm Point-to-Point 

Transmission Service using the 

curtailment priority pursuant to Section 

13.6. Such conditions must be identified 

in the Transmission Customer’s Service 

Agreement. 

1.47 System Impact Study 

An assessment by the Transmission 

Provider of (i) the adequacy of the 

Transmission System to accommodate a 

request for either Firm Point-To-Point 

Transmission Service or Network 

Integration Transmission Service and 

(ii) whether any additional costs may be 

incurred in order to provide 

transmission service. 

1.48 Third-Party Sale 

Any sale for resale in interstate 

commerce to a Power Purchaser that is 

not designated as part of Network Load 

under the Network Integration 

Transmission Service. 

1.49 Transmission Customer 

Any Eligible Customer (or its 

Designated Agent) that (i) executes a 

Service Agreement, or (ii) requests in 

writing that the Transmission Provider 

file with the Commission, a proposed 

unexecuted Service Agreement to 

receive transmission service under Part 

II of the Tariff. This term is used in the 

Part I Common Service Provisions to 

include customers receiving 

transmission service under Part II and 

Part III of this Tariff. 

1.50 Transmission Provider 

The public utility (or its Designated 

Agent) that owns, controls, or operates 

facilities used for the transmission of 

electric energy in interstate commerce 

and provides transmission service under 

the Tariff. 

1.51 Transmission Provider’s Monthly 

Transmission System Peak 

The maximum firm usage of the 

Transmission Provider’s Transmission 

System in a calendar month. 

1.52 Transmission Service 

Point-To-Point Transmission Service 

provided under Part II of the Tariff on 

a firm and non-firm basis. 

1.53 Transmission System 

The facilities owned, controlled or 

operated by the Transmission Provider 

that are used to provide transmission 

service under Part II and Part III of the 

Tariff. 

2 Initial Allocation and Renewal 

Procedures 

2.1 Initial Allocation of Available 

Transfer Capability 

For purposes of determining whether 

existing capability on the Transmission 

Provider’s Transmission System is 

adequate to accommodate a request for 

firm service under this Tariff, all 

Completed Applications for new firm 

transmission service received during the 

initial sixty (60) day period 

commencing with the effective date of 

the Tariff will be deemed to have been 

filed simultaneously. A lottery system 

conducted by an independent party 

shall be used to assign priorities for 

Completed Applications filed 

simultaneously. All Completed 

Applications for firm transmission 

service received after the initial sixty 

(60) day period shall be assigned a 

priority pursuant to Section 13.2. 

2.2 Reservation Priority For Existing 

Firm Service Customers 

Existing firm service customers 

(wholesale requirements and 

transmission-only, with a contract term 

of five years or more), have the right to 

continue to take transmission service 

from the Transmission Provider when 

the contract expires, rolls over or is 

renewed. This transmission reservation 

priority is independent of whether the 

existing customer continues to purchase 

capacity and energy from the 

Transmission Provider or elects to 

purchase capacity and energy from 

another supplier. If at the end of the 

contract term, the Transmission 

Provider’s Transmission System cannot 

accommodate all of the requests for 

transmission service, the existing firm 

service customer must agree to accept a 

contract term at least equal to the longer 

of a competing request by any new 

Eligible Customer or five years and to 

pay the current just and reasonable rate, 

as approved by the Commission, for 

such service. The existing firm service 

customer must provide notice to the 

Transmission Provider whether it will 

exercise its right of first refusal no less 

than one year prior to the expiration 

date of its transmission service 

agreement. This transmission 

reservation priority for existing firm 

service customers is an ongoing right 

that may be exercised at the end of all 

firm contract terms of five years or 

longer. Service agreements subject to a 

right of first refusal entered into prior to 

[the acceptance by the Commission of 

the Transmission Provider’s Attachment 

K], unless terminated, will become 

subject to the five year/one year 

requirement on the first rollover date 

after [the acceptance by the Commission 

of the Transmission Provider’s 

Attachment K]. 

3 Ancillary Services 

Ancillary Services are needed with 

transmission service to maintain 

reliability within and among the Control 

Areas affected by the transmission 

service. The Transmission Provider is 

required to provide (or offer to arrange 

with the local Control Area operator as 

discussed below), and the Transmission 

Customer is required to purchase, the 

following Ancillary Services (i) 

Scheduling, System Control and 

Dispatch, and (ii) Reactive Supply and 

Voltage Control from Generation or 

Other Sources. 

The Transmission Provider is 

required to offer to provide (or offer to 

arrange with the local Control Area 

operator as discussed below) the 

following Ancillary Services only to the 

Transmission Customer serving load 

within the Transmission Provider’s 

Control Area (i) Regulation and 

Frequency Response, (ii) Energy 

Imbalance, (iii) Operating Reserve—


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Spinning, (iv) Operating Reserve—

Supplemental, and (v) Generator 

Imbalance. The Transmission Customer 

serving load within the Transmission 

Provider’s Control Area is required to 

acquire these Ancillary Services, 

whether from the Transmission 

Provider, from a third party, or by selfsupply. The Transmission Customer 

may not decline the Transmission 

Provider’s offer of Ancillary Services 

unless it demonstrates that it has 

acquired the Ancillary Services from 

another source. The Transmission 

Customer must list in its Application 

which Ancillary Services it will 

purchase from the Transmission 

Provider. A Transmission Customer that 

exceeds its firm reserved capacity at any 

Point of Receipt or Point of Delivery or 

an Eligible Customer that uses 

Transmission Service at a Point of 

Receipt or Point of Delivery that it has 

not reserved is required to pay for all of 

the Ancillary Services identified in this 

section that were provided by the 

Transmission Provider associated with 

the unreserved service. The 

Transmission Customer or Eligible 

Customer will pay for Ancillary 

Services based on the amount of 

transmission service it used but did not 

reserve. 

If the Transmission Provider is a 

public utility providing transmission 

service but is not a Control Area 

operator, it may be unable to provide 

some or all of the Ancillary Services. In 

this case, the Transmission Provider can 

fulfill its obligation to provide Ancillary 

Services by acting as the Transmission 

Customer’s agent to secure these 

Ancillary Services from the Control 

Area operator. The Transmission 

Customer may elect to (i) have the 

Transmission Provider act as its agent, 

(ii) secure the Ancillary Services 

directly from the Control Area operator, 

or (iii) secure the Ancillary Services 

(discussed in Schedules 3, 4, 5, 6 and 

9) from a third party or by self-supply 

when technically feasible. 

The Transmission Provider shall 

specify the rate treatment and all related 

terms and conditions in the event of an 

unauthorized use of Ancillary Services 

by the Transmission Customer. 

The specific Ancillary Services, prices 

and/or compensation methods are 

described on the Schedules that are 

attached to and made a part of the 

Tariff. Three principal requirements 

apply to discounts for Ancillary 

Services provided by the Transmission 

Provider in conjunction with its 

provision of transmission service as 

follows: (1) Any offer of a discount 

made by the Transmission Provider 

must be announced to all Eligible 

Customers solely by posting on the 

OASIS, (2) any customer-initiated 

requests for discounts (including 

requests for use by one’s wholesale 

merchant or an affiliate’s use) must 

occur solely by posting on the OASIS, 

and (3) once a discount is negotiated, 

details must be immediately posted on 

the OASIS. A discount agreed upon for 

an Ancillary Service must be offered for 

the same period to all Eligible 

Customers on the Transmission 

Provider’s system. Sections 3.1 through 

3.7 below list the seven Ancillary 

Services. 

3.1 Scheduling, System Control and 

Dispatch Service 

The rates and/or methodology are 

described in Schedule 1. 

3.2 Reactive Supply and Voltage 

Control from Generation or Other 

Sources Service 

The rates and/or methodology are 

described in Schedule 2. 

3.3 Regulation and Frequency 

Response Service 

Where applicable the rates and/or 

methodology are described in Schedule 

3. 

3.4 Energy Imbalance Service 

Where applicable the rates and/or 

methodology are described in Schedule 

4. 

3.5 Operating Reserve—Spinning 

Reserve Service 

Where applicable the rates and/or 

methodology are described in Schedule 

5. 

3.6 Operating Reserve—Supplemental 

Reserve Service 

Where applicable the rates and/or 

methodology are described in Schedule 

6. 

3.7 Generator Imbalance Service 

Where applicable the rates and/or 

methodology are described in Schedule 

9. 

4 Open Access Same-Time 

Information System (OASIS) 

Terms and conditions regarding Open 

Access Same-Time Information System 

and standards of conduct are set forth in 

18 CFR part 37 of the Commission’s 

regulations (Open Access Same-Time 

Information System and Standards of 

Conduct for Public Utilities) and 18 CFR 

part 38 of the Commission’s regulations 

(Business Practice Standards and 

Communication Protocols for Public 

Utilities). In the event available transfer 

capability as posted on the OASIS is 

insufficient to accommodate a request 

for firm transmission service, additional 

studies may be required as provided by 

this Tariff pursuant to Sections 19 and 

32. 

The Transmission Provider shall post 

on its public Web site all rules, 

standards and practices that (i) relate to 

the terms and conditions of 

transmission service, (ii) are not subject 

to a North American Energy Standards 

Board (NAESB) copyright restriction, 

and (iii) are not otherwise included in 

this Tariff. The Transmission Provider 

shall post on OASIS an electronic link 

to these rules, standards and practices, 

and shall post on its public Web site an 

electronic link to the NAESB Web site 

where any rules, standards and 

practices that are protected by copyright 

may be obtained. The Transmission 

Provider shall also make available on its 

public Web site a statement of the 

process by which the Transmission 

Provider shall add, delete or otherwise 

modify the rules, standards and 

practices that are posted on its website. 

Such process shall set forth the means 

by which the Transmission Provider 

shall provide reasonable advance notice 

to Transmission Customers and Eligible 

Customers of any such additions, 

deletions or modifications, the 

associated effective date, and any 

additional implementation procedures 

that the Transmission Provider deems 

appropriate. 

5 Local Furnishing Bonds 

5.1 Transmission Providers That Own 

Facilities Financed by Local Furnishing 

Bonds 

This provision is applicable only to 

Transmission Providers that have 

financed facilities for the local 

furnishing of electric energy with taxexempt bonds, as described in Section 

142(f) of the Internal Revenue Code 

(‘‘local furnishing bonds’’). 

Notwithstanding any other provision of 

this Tariff, the Transmission Provider 

shall not be required to provide 

transmission service to any Eligible 

Customer pursuant to this Tariff if the 

provision of such transmission service 

would jeopardize the tax-exempt status 

of any local furnishing bond(s) used to 

finance the Transmission Provider’s 

facilities that would be used in 

providing such transmission service. 

5.2 Alternative Procedures for 

Requesting Transmission Service 

(i) If the Transmission Provider 

determines that the provision of 

transmission service requested by an 

Eligible Customer would jeopardize the 

tax-exempt status of any local 


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furnishing bond(s) used to finance its 

facilities that would be used in 

providing such transmission service, it 

shall advise the Eligible Customer 

within thirty (30) days of receipt of the 

Completed Application. 

(ii) If the Eligible Customer thereafter 

renews its request for the same 

transmission service referred to in (i) by 

tendering an application under Section 

211 of the Federal Power Act, the 

Transmission Provider, within ten (10) 

days of receiving a copy of the Section 

211 application, will waive its rights to 

a request for service under Section 

213(a) of the Federal Power Act and to 

the issuance of a proposed order under 

Section 212(c) of the Federal Power Act. 

The Commission, upon receipt of the 

Transmission Provider’s waiver of its 

rights to a request for service under 

Section 213(a) of the Federal Power Act 

and to the issuance of a proposed order 

under Section 212(c) of the Federal 

Power Act, shall issue an order under 

Section 211 of the Federal Power Act. 

Upon issuance of the order under 

Section 211 of the Federal Power Act, 

the Transmission Provider shall be 

required to provide the requested 

transmission service in accordance with 

the terms and conditions of this Tariff. 

6 Reciprocity 

A Transmission Customer receiving 

transmission service under this Tariff 

agrees to provide comparable 

transmission service that it is capable of 

providing to the Transmission Provider 

on similar terms and conditions over 

facilities used for the transmission of 

electric energy owned, controlled or 

operated by the Transmission Customer 

and over facilities used for the 

transmission of electric energy owned, 

controlled or operated by the 

Transmission Customer’s corporate 

affiliates. A Transmission Customer that 

is a member of, or takes transmission 

service from, a power pool, Regional 

Transmission Group, Regional 

Transmission Organization (RTO), 

Independent System Operator (ISO) or 

other transmission organization 

approved by the Commission for the 

operation of transmission facilities also 

agrees to provide comparable 

transmission service to the members of 

such power pool and Regional 

Transmission Group, RTO, ISO or other 

transmission organization on similar 

terms and conditions over facilities used 

for the transmission of electric energy 

owned, controlled or operated by the 

Transmission Customer and over 

facilities used for the transmission of 

electric energy owned, controlled or 

operated by the Transmission 

Customer’s corporate affiliates. 

This reciprocity requirement applies 

not only to the Transmission Customer 

that obtains transmission service under 

the Tariff, but also to all parties to a 

transaction that involves the use of 

transmission service under the Tariff, 

including the power seller, buyer and 

any intermediary, such as a power 

marketer. This reciprocity requirement 

also applies to any Eligible Customer 

that owns, controls or operates 

transmission facilities that uses an 

intermediary, such as a power marketer, 

to request transmission service under 

the Tariff. If the Transmission Customer 

does not own, control or operate 

transmission facilities, it must include 

in its Application a sworn statement of 

one of its duly authorized officers or 

other representatives that the purpose of 

its Application is not to assist an 

Eligible Customer to avoid the 

requirements of this provision. 

7 Billing and Payment 

7.1 Billing Procedure 

Within a reasonable time after the first 

day of each month, the Transmission 

Provider shall submit an invoice to the 

Transmission Customer for the charges 

for all services furnished under the 

Tariff during the preceding month. The 

invoice shall be paid by the 

Transmission Customer within twenty 

(20) days of receipt. All payments shall 

be made in immediately available funds 

payable to the Transmission Provider, or 

by wire transfer to a bank named by the 

Transmission Provider. 

7.2 Interest on Unpaid Balances 

Interest on any unpaid amounts 

(including amounts placed in escrow) 

shall be calculated in accordance with 

the methodology specified for interest 

on refunds in the Commission’s 

regulations at 18 CFR 35.19a(a)(2)(iii). 

Interest on delinquent amounts shall be 

calculated from the due date of the bill 

to the date of payment. When payments 

are made by mail, bills shall be 

considered as having been paid on the 

date of receipt by the Transmission 

Provider. 

7.3 Customer Default 

In the event the Transmission 

Customer fails, for any reason other than 

a billing dispute as described below, to 

make payment to the Transmission 

Provider on or before the due date as 

described above, and such failure of 

payment is not corrected within thirty 

(30) calendar days after the 

Transmission Provider notifies the 

Transmission Customer to cure such 

failure, a default by the Transmission 

Customer shall be deemed to exist. 

Upon the occurrence of a default, the 

Transmission Provider may initiate a 

proceeding with the Commission to 

terminate service but shall not terminate 

service until the Commission so 

approves any such request. In the event 

of a billing dispute between the 

Transmission Provider and the 

Transmission Customer, the 

Transmission Provider will continue to 

provide service under the Service 

Agreement as long as the Transmission 

Customer (i) continues to make all 

payments not in dispute, and (ii) pays 

into an independent escrow account the 

portion of the invoice in dispute, 

pending resolution of such dispute. If 

the Transmission Customer fails to meet 

these two requirements for continuation 

of service, then the Transmission 

Provider may provide notice to the 

Transmission Customer of its intention 

to suspend service in sixty (60) days, in 

accordance with Commission policy. 

8 Accounting for the Transmission 

Provider’s Use of the Tariff 

The Transmission Provider shall 

record the following amounts, as 

outlined below. 

8.1 Transmission Revenues 

Include in a separate operating 

revenue account or subaccount the 

revenues it receives from Transmission 

Service when making Third-Party Sales 

under Part II of the Tariff. 

8.2 Study Costs and Revenues 

Include in a separate transmission 

operating expense account or 

subaccount, costs properly chargeable to 

expense that are incurred to perform 

any System Impact Studies or Facilities 

Studies which the Transmission 

Provider conducts to determine if it 

must construct new transmission 

facilities or upgrades necessary for its 

own uses, including making Third-Party 

Sales under the Tariff; and include in a 

separate operating revenue account or 

subaccount the revenues received for 

System Impact Studies or Facilities 

Studies performed when such amounts 

are separately stated and identified in 

the Transmission Customer’s billing 

under the Tariff. 

9 Regulatory Filings 

Nothing contained in the Tariff or any 

Service Agreement shall be construed as 

affecting in any way the right of the 

Transmission Provider to unilaterally 

make application to the Commission for 

a change in rates, terms and conditions, 

charges, classification of service, Service 

Agreement, rule or regulation under 

Section 205 of the Federal Power Act 

and pursuant to the Commission’s rules 


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and regulations promulgated 

thereunder. 

Nothing contained in the Tariff or any 

Service Agreement shall be construed as 

affecting in any way the ability of any 

Party receiving service under the Tariff 

to exercise its rights under the Federal 

Power Act and pursuant to the 

Commission’s rules and regulations 

promulgated thereunder. 

10 Force Majeure and Indemnification 

10.1 Force Majeure 

An event of Force Majeure means any 

act of God, labor disturbance, act of the 

public enemy, war, insurrection, riot, 

fire, storm or flood, explosion, breakage 

or accident to machinery or equipment, 

any Curtailment, order, regulation or 

restriction imposed by governmental 

military or lawfully established civilian 

authorities, or any other cause beyond a 

Party’s control. A Force Majeure event 

does not include an act of negligence or 

intentional wrongdoing. 

Neither the Transmission Provider 

nor the Transmission Customer will be 

considered in default as to any 

obligation under this Tariff if prevented 

from fulfilling the obligation due to an 

event of Force Majeure. However, a 

Party whose performance under this 

Tariff is hindered by an event of Force 

Majeure shall make all reasonable 

efforts to perform its obligations under 

this Tariff. 

10.2 Indemnification 

The Transmission Customer shall at 

all times indemnify, defend, and save 

the Transmission Provider harmless 

from, any and all damages, losses, 

claims, including claims and actions 

relating to injury to or death of any 

person or damage to property, demands, 

suits, recoveries, costs and expenses, 

court costs, attorney fees, and all other 

obligations by or to third parties, arising 

out of or resulting from the 

Transmission Provider’s performance of 

its obligations under this Tariff on 

behalf of the Transmission Customer, 

except in cases of negligence or 

intentional wrongdoing by the 

Transmission Provider. 

11 Creditworthiness 

The Transmission Provider will 

specify its Creditworthiness procedures 

in Attachment L. 

12 Dispute Resolution Procedures 

12.1 Internal Dispute Resolution 

Procedures 

Any dispute between a Transmission 

Customer and the Transmission 

Provider involving transmission service 

under the Tariff (excluding applications 

for rate changes or other changes to the 

Tariff, or to any Service Agreement 

entered into under the Tariff, which 

shall be presented directly to the 

Commission for resolution) shall be 

referred to a designated senior 

representative of the Transmission 

Provider and a senior representative of 

the Transmission Customer for 

resolution on an informal basis as 

promptly as practicable. In the event the 

designated representatives are unable to 

resolve the dispute within thirty (30) 

days [or such other period as the Parties 

may agree upon] by mutual agreement, 

such dispute may be submitted to 

arbitration and resolved in accordance 

with the arbitration procedures set forth 

below. 

12.2 External Arbitration Procedures 

Any arbitration initiated under the 

Tariff shall be conducted before a single 

neutral arbitrator appointed by the 

Parties. If the Parties fail to agree upon 

a single arbitrator within ten (10) days 

of the referral of the dispute to 

arbitration, each Party shall choose one 

arbitrator who shall sit on a threemember arbitration panel. The two 

arbitrators so chosen shall within 

twenty (20) days select a third arbitrator 

to chair the arbitration panel. In either 

case, the arbitrators shall be 

knowledgeable in electric utility 

matters, including electric transmission 

and bulk power issues, and shall not 

have any current or past substantial 

business or financial relationships with 

any party to the arbitration (except prior 

arbitration). The arbitrator(s) shall 

provide each of the Parties an 

opportunity to be heard and, except as 

otherwise provided herein, shall 

generally conduct the arbitration in 

accordance with the Commercial 

Arbitration Rules of the American 

Arbitration Association and any 

applicable Commission regulations or 

Regional Transmission Group rules. 

12.3 Arbitration Decisions 

Unless otherwise agreed, the 

arbitrator(s) shall render a decision 

within ninety (90) days of appointment 

and shall notify the Parties in writing of 

such decision and the reasons therefor. 

The arbitrator(s) shall be authorized 

only to interpret and apply the 

provisions of the Tariff and any Service 

Agreement entered into under the Tariff 

and shall have no power to modify or 

change any of the above in any manner. 

The decision of the arbitrator(s) shall be 

final and binding upon the Parties, and 

judgment on the award may be entered 

in any court having jurisdiction. The 

decision of the arbitrator(s) may be 

appealed solely on the grounds that the 

conduct of the arbitrator(s), or the 

decision itself, violated the standards 

set forth in the Federal Arbitration Act 

and/or the Administrative Dispute 

Resolution Act. The final decision of the 

arbitrator must also be filed with the 

Commission if it affects jurisdictional 

rates, terms and conditions of service or 

facilities. 

12.4 Costs 

Each Party shall be responsible for its 

own costs incurred during the 

arbitration process and for the following 

costs, if applicable: 

1. The cost of the arbitrator chosen by 

the Party to sit on the three member 

panel and one half of the cost of the 

third arbitrator chosen; or 

2. One half the cost of the single 

arbitrator jointly chosen by the Parties. 

12.5 Rights Under the Federal Power 

Act 

Nothing in this section shall restrict 

the rights of any party to file a 

Complaint with the Commission under 

relevant provisions of the Federal Power 

Act. 

II. Point-To-Point Transmission Service 

Preamble 

The Transmission Provider will 

provide Firm and Non-Firm Point-ToPoint Transmission Service pursuant to 

the applicable terms and conditions of 

this Tariff. Point-To-Point Transmission 

Service is for the receipt of capacity and 

energy at designated Point(s) of Receipt 

and the transfer of such capacity and 

energy to designated Point(s) of 

Delivery. 

13 Nature of Firm Point-To-Point 

Transmission Service 

13.1 Term 

The minimum term of Firm Point-ToPoint Transmission Service shall be one 

day and the maximum term shall be 

specified in the Service Agreement. 

13.2 Reservation Priority 

(i) Long-Term Firm Point-To-Point 

Transmission Service shall be available 

on a first-come, first-served basis, i.e., in 

the chronological sequence in which 

each Transmission Customer has 

requested service. 

(ii) Reservations for Short-Term Firm 

Point-To-Point Transmission Service 

will be conditional based upon the 

length of the requested transaction. 

However, Pre-Confirmed Applications 

for Short-Term Point-to-Point 

Transmission Service will receive 

priority over earlier-submitted requests 

that are not Pre-Confirmed and that 

have equal or shorter duration. Among 


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requests with the same duration and 

pre-confirmation status (Pre-Confirmed 

or not confirmed), priority will be given 

to an Eligible Customer’s request that 

offers the highest price, followed by the 

date and time of the request. 

(iii) If the Transmission System 

becomes oversubscribed, requests for 

longer term service may preempt 

requests for shorter term service up to 

the following deadlines: one day before 

the commencement of daily service, one 

week before the commencement of 

weekly service, and one month before 

the commencement of monthly service. 

Before the conditional reservation 

deadline, if available transfer capability 

is insufficient to satisfy all Applications, 

an Eligible Customer with a reservation 

for shorter term service or equal 

duration service and lower price has the 

right of first refusal to match any longer 

term request or equal duration service 

with a higher price before losing its 

reservation priority. A longer term 

competing request for Short-Term Firm 

Point-To-Point Transmission Service 

will be granted if the Eligible Customer 

with the right of first refusal does not 

agree to match the competing request 

within 24 hours (or earlier if necessary 

to comply with the scheduling 

deadlines provided in section 13.8) from 

being notified by the Transmission 

Provider of a longer-term competing 

request for Short-Term Firm Point-ToPoint Transmission Service. When a 

longer duration request preempts 

multiple shorter duration requests, the 

shorter duration requests shall have 

simultaneous opportunities to exercise 

the right of first refusal. Duration, preconfirmation status, price and time of 

response will be used to determine the 

order by which the multiple shorter 

duration requests will be able to 

exercise the right of first refusal. After 

the conditional reservation deadline, 

service will commence pursuant to the 

terms of Part II of the Tariff. 

(iv) Firm Point-To-Point Transmission 

Service will always have a reservation 

priority over Non-Firm Point-To-Point 

Transmission Service under the Tariff. 

All Long-Term Firm Point-To-Point 

Transmission Service will have equal 

reservation priority with Native Load 

Customers and Network Customers. 

Reservation priorities for existing firm 

service customers are provided in 

Section 2.2. 

13.3 Use of Firm Transmission Service 

by the Transmission Provider 

The Transmission Provider will be 

subject to the rates, terms and 

conditions of Part II of the Tariff when 

making Third-Party Sales under (i) 

agreements executed on or after [insert 

date sixty (60) days after publication in 

Federal Register] or (ii) agreements 

executed prior to the aforementioned 

date that the Commission requires to be 

unbundled, by the date specified by the 

Commission. The Transmission 

Provider will maintain separate 

accounting, pursuant to Section 8, for 

any use of the Point-To-Point 

Transmission Service to make ThirdParty Sales. 

13.4 Service Agreements 

The Transmission Provider shall offer 

a standard form Firm Point-To-Point 

Transmission Service Agreement 

(Attachment A) to an Eligible Customer 

when it submits a Completed 

Application for Long-Term Firm PointTo-Point Transmission Service. The 

Transmission Provider shall offer a 

standard form Firm Point-To-Point 

Transmission Service Agreement 

(Attachment A) to an Eligible Customer 

when it first submits a Completed 

Application for Short-Term Firm PointTo-Point Transmission Service pursuant 

to the Tariff. Executed Service 

Agreements that contain the information 

required under the Tariff shall be filed 

with the Commission in compliance 

with applicable Commission 

regulations. An Eligible Customer that 

uses Transmission Service at a Point of 

Receipt or Point of Delivery that it has 

not reserved and that has not executed 

a Service Agreement will be deemed, for 

purposes of assessing any appropriate 

charges and penalties, to have executed 

the appropriate Service Agreement. The 

Service Agreement shall, when 

applicable, specify any conditional 

curtailment options selected by the 

Transmission Customer. Where the 

Service Agreement contains conditional 

curtailment options and is subject to a 

biennial reassessment as described in 

Section 15.4, the Transmission Provider 

shall provide the Transmission 

Customer notice of any changes to the 

curtailment conditions no less than 90 

days prior to the date for imposition of 

new curtailment conditions. Concurrent 

with such notice, the Transmission 

Provider shall provide the Transmission 

Customer with the reassessment study 

and a narrative description of the study, 

including the reasons for changes to the 

number of hours per year or System 

Conditions under which conditional 

curtailment may occur. 

13.5 Transmission Customer 

Obligations for Facility Additions or 

Redispatch Costs 

In cases where the Transmission 

Provider determines that the 

Transmission System is not capable of 

providing Firm Point-To-Point 

Transmission Service without (1) 

degrading or impairing the reliability of 

service to Native Load Customers, 

Network Customers and other 

Transmission Customers taking Firm 

Point-To-Point Transmission Service, or 

(2) interfering with the Transmission 

Provider’s ability to meet prior firm 

contractual commitments to others, the 

Transmission Provider will be obligated 

to expand or upgrade its Transmission 

System pursuant to the terms of Section 

15.4. The Transmission Customer must 

agree to compensate the Transmission 

Provider for any necessary transmission 

facility additions pursuant to the terms 

of Section 27. To the extent the 

Transmission Provider can relieve any 

system constraint by redispatching the 

Transmission Provider’s resources, it 

shall do so, provided that the Eligible 

Customer agrees to compensate the 

Transmission Provider pursuant to the 

terms of Section 27 and agrees to either 

(i) compensate the Transmission 

Provider for any necessary transmission 

facility additions or (ii) accept the 

service subject to a biennial 

reassessment by the Transmission 

Provider of redispatch requirements as 

described in Section 15.4. Any 

redispatch, Network Upgrade or Direct 

Assignment Facilities costs to be 

charged to the Transmission Customer 

on an incremental basis under the Tariff 

will be specified in the Service 

Agreement prior to initiating service. 

13.6 Curtailment of Firm Transmission 

Service 

In the event that a Curtailment on the 

Transmission Provider’s Transmission 

System, or a portion thereof, is required 

to maintain reliable operation of such 

system and the system directly and 

indirectly interconnected with 

Transmission Provider’s Transmission 

System, Curtailments will be made on a 

non-discriminatory basis to the 

transaction(s) that effectively relieve the 

constraint. Transmission Provider may 

elect to implement such Curtailments 

pursuant to the Transmission Loading 

Relief procedures specified in 

Attachment J. If multiple transactions 

require Curtailment, to the extent 

practicable and consistent with Good 

Utility Practice, the Transmission 

Provider will curtail service to Network 

Customers and Transmission Customers 

taking Firm Point-To-Point 

Transmission Service on a basis 

comparable to the curtailment of service 

to the Transmission Provider’s Native 

Load Customers. All Curtailments will 

be made on a non-discriminatory basis, 

however, Non-Firm Point-To-Point 

Transmission Service shall be 

subordinate to Firm Transmission 


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Service. Long-Term Firm Point-to-Point 

Service subject to conditions described 

in Section 15.4 shall be curtailed with 

secondary service in cases where the 

conditions apply, but otherwise will be 

curtailed on a pro rata basis with other 

Firm Transmission Service. When the 

Transmission Provider determines that 

an electrical emergency exists on its 

Transmission System and implements 

emergency procedures to Curtail Firm 

Transmission Service, the Transmission 

Customer shall make the required 

reductions upon request of the 

Transmission Provider. However, the 

Transmission Provider reserves the right 

to Curtail, in whole or in part, any Firm 

Transmission Service provided under 

the Tariff when, in the Transmission 

Provider’s sole discretion, an emergency 

or other unforeseen condition impairs or 

degrades the reliability of its 

Transmission System. The Transmission 

Provider will notify all affected 

Transmission Customers in a timely 

manner of any scheduled Curtailments. 

13.7 Classification of Firm 

Transmission Service 

(a) The Transmission Customer taking 

Firm Point-To-Point Transmission 

Service may (1) change its Receipt and 

Delivery Points to obtain service on a 

non-firm basis consistent with the terms 

of Section 22.1 or (2) request a 

modification of the Points of Receipt or 

Delivery on a firm basis pursuant to the 

terms of Section 22.2. 

(b) The Transmission Customer may 

purchase transmission service to make 

sales of capacity and energy from 

multiple generating units that are on the 

Transmission Provider’s Transmission 

System. For such a purchase of 

transmission service, the resources will 

be designated as multiple Points of 

Receipt, unless the multiple generating 

units are at the same generating plant in 

which case the units would be treated 

as a single Point of Receipt. 

(c) The Transmission Provider shall 

provide firm deliveries of capacity and 

energy from the Point(s) of Receipt to 

the Point(s) of Delivery. Each Point of 

Receipt at which firm transmission 

capacity is reserved by the Transmission 

Customer shall be set forth in the Firm 

Point-To-Point Service Agreement for 

Long-Term Firm Transmission Service 

along with a corresponding capacity 

reservation associated with each Point 

of Receipt. Points of Receipt and 

corresponding capacity reservations 

shall be as mutually agreed upon by the 

Parties for Short-Term Firm 

Transmission. Each Point of Delivery at 

which firm transfer capability is 

reserved by the Transmission Customer 

shall be set forth in the Firm Point-ToPoint Service Agreement for Long-Term 

Firm Transmission Service along with a 

corresponding capacity reservation 

associated with each Point of Delivery. 

Points of Delivery and corresponding 

capacity reservations shall be as 

mutually agreed upon by the Parties for 

Short-Term Firm Transmission. The 

greater of either (1) the sum of the 

capacity reservations at the Point(s) of 

Receipt, or (2) the sum of the capacity 

reservations at the Point(s) of Delivery 

shall be the Transmission Customer’s 

Reserved Capacity. The Transmission 

Customer will be billed for its Reserved 

Capacity under the terms of Schedule 7. 

The Transmission Customer may not 

exceed its firm capacity reserved at each 

Point of Receipt and each Point of 

Delivery except as otherwise specified 

in Section 22. The Transmission 

Provider shall specify the rate treatment 

and all related terms and conditions 

applicable in the event that a 

Transmission Customer (including 

Third-Party Sales by the Transmission 

Provider) exceeds its firm reserved 

capacity at any Point of Receipt or Point 

of Delivery or uses Transmission 

Service at a Point of Receipt or Point of 

Delivery that it has not reserved. 

13.8 Scheduling of Firm Point-ToPoint Transmission Service 

Schedules for the Transmission 

Customer’s Firm Point-To-Point 

Transmission Service must be submitted 

to the Transmission Provider no later 

than 10 a.m. [or a reasonable time that 

is generally accepted in the region and 

is consistently adhered to by the 

Transmission Provider] of the day prior 

to commencement of such service. 

Schedules submitted after 10 a.m. will 

be accommodated, if practicable. Hourto-hour schedules of any capacity and 

energy that is to be delivered must be 

stated in increments of 1,000 kW per 

hour [or a reasonable increment that is 

generally accepted in the region and is 

consistently adhered to by the 

Transmission Provider]. Transmission 

Customers within the Transmission 

Provider’s service area with multiple 

requests for Transmission Service at a 

Point of Receipt, each of which is under 

1,000 kW per hour, may consolidate 

their service requests at a common point 

of receipt into units of 1,000 kW per 

hour for scheduling and billing 

purposes. Scheduling changes will be 

permitted up to twenty (20) minutes [or 

a reasonable time that is generally 

accepted in the region and is 

consistently adhered to by the 

Transmission Provider] before the start 

of the next clock hour provided that the 

Delivering Party and Receiving Party 

also agree to the schedule modification. 

The Transmission Provider will furnish 

to the Delivering Party’s system 

operator, hour-to-hour schedules equal 

to those furnished by the Receiving 

Party (unless reduced for losses) and 

shall deliver the capacity and energy 

provided by such schedules. Should the 

Transmission Customer, Delivering 

Party or Receiving Party revise or 

terminate any schedule, such party shall 

immediately notify the Transmission 

Provider, and the Transmission Provider 

shall have the right to adjust 

accordingly the schedule for capacity 

and energy to be received and to be 

delivered. 

14 Nature of Non-Firm Point-To-Point 

Transmission Service 

14.1 Term 

Non-Firm Point-To-Point 

Transmission Service will be available 

for periods ranging from one (1) hour to 

one (1) month. However, a Purchaser of 

Non-Firm Point-To-Point Transmission 

Service will be entitled to reserve a 

sequential term of service (such as a 

sequential monthly term without having 

to wait for the initial term to expire 

before requesting another monthly term) 

so that the total time period for which 

the reservation applies is greater than 

one month, subject to the requirements 

of Section 18.3. 

14.2 Reservation Priority 

Non-Firm Point-To-Point 

Transmission Service shall be available 

from transfer capability in excess of that 

needed for reliable service to Native 

Load Customers, Network Customers 

and other Transmission Customers 

taking Long-Term and Short-Term Firm 

Point-To-Point Transmission Service. A 

higher priority will be assigned first to 

reservations with a longer duration of 

service and second to Pre-Confirmed 

Applications. In the event the 

Transmission System is constrained, 

competing requests of the same PreConfirmation status and equal duration 

will be prioritized based on the highest 

price offered by the Eligible Customer 

for the Transmission Service. Eligible 

Customers that have already reserved 

shorter term service have the right of 

first refusal to match any longer term 

reservation before being preempted. A 

longer term competing request for NonFirm Point-To-Point Transmission 

Service will be granted if the Eligible 

Customer with the right of first refusal 

does not agree to match the competing 

request: (a) Immediately for hourly NonFirm Point-To-Point Transmission 

Service after notification by the 

Transmission Provider; and, (b) within 

24 hours (or earlier if necessary to 


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comply with the scheduling deadlines 

provided in section 14.6) for Non-Firm 

Point-To-Point Transmission Service 

other than hourly transactions after 

notification by the Transmission 

Provider. Transmission service for 

Network Customers from resources 

other than designated Network 

Resources will have a higher priority 

than any Non-Firm Point-To-Point 

Transmission Service. Non-Firm PointTo-Point Transmission Service over 

secondary Point(s) of Receipt and 

Point(s) of Delivery will have the lowest 

reservation priority under the Tariff. 

14.3 Use of Non-Firm Point-To-Point 

Transmission Service by the 

Transmission Provider 

The Transmission Provider will be 

subject to the rates, terms and 

conditions of Part II of the Tariff when 

making Third-Party Sales under (i) 

agreements executed on or after May 14, 

2007 or (ii) agreements executed prior to 

the aforementioned date that the 

Commission requires to be unbundled, 

by the date specified by the 

Commission. The Transmission 

Provider will maintain separate 

accounting, pursuant to Section 8, for 

any use of Non-Firm Point-To-Point 

Transmission Service to make ThirdParty Sales. 

14.4 Service Agreements 

The Transmission Provider shall offer 

a standard form Non-Firm Point-ToPoint Transmission Service Agreement 

(Attachment B) to an Eligible Customer 

when it first submits a Completed 

Application for Non-Firm Point-ToPoint Transmission Service pursuant to 

the Tariff. Executed Service Agreements 

that contain the information required 

under the Tariff shall be filed with the 

Commission in compliance with 

applicable Commission regulations. 

14.5 Classification of Non-Firm PointTo-Point Transmission Service 

Non-Firm Point-To-Point 

Transmission Service shall be offered 

under terms and conditions contained 

in Part II of the Tariff. The Transmission 

Provider undertakes no obligation under 

the Tariff to plan its Transmission 

System in order to have sufficient 

capacity for Non-Firm Point-To-Point 

Transmission Service. Parties requesting 

Non-Firm Point-To-Point Transmission 

Service for the transmission of firm 

power do so with the full realization 

that such service is subject to 

availability and to Curtailment or 

Interruption under the terms of the 

Tariff. The Transmission Provider shall 

specify the rate treatment and all related 

terms and conditions applicable in the 

event that a Transmission Customer 

(including Third-Party Sales by the 

Transmission Provider) exceeds its nonfirm capacity reservation. Non-Firm 

Point-To-Point Transmission Service 

shall include transmission of energy on 

an hourly basis and transmission of 

scheduled short-term capacity and 

energy on a daily, weekly or monthly 

basis, but not to exceed one month’s 

reservation for any one Application, 

under Schedule 8. 

14.6 Scheduling of Non-Firm PointTo-Point Transmission Service 

Schedules for Non-Firm Point-ToPoint Transmission Service must be 

submitted to the Transmission Provider 

no later than 2 p.m. [or a reasonable 

time that is generally accepted in the 

region and is consistently adhered to by 

the Transmission Provider] of the day 

prior to commencement of such service. 

Schedules submitted after 2 p.m. will be 

accommodated, if practicable. Hour-tohour schedules of energy that is to be 

delivered must be stated in increments 

of 1,000 kW per hour [or a reasonable 

increment that is generally accepted in 

the region and is consistently adhered to 

by the Transmission Provider]. 

Transmission Customers within the 

Transmission Provider’s service area 

with multiple requests for Transmission 

Service at a Point of Receipt, each of 

which is under 1,000 kW per hour, may 

consolidate their schedules at a 

common Point of Receipt into units of 

1,000 kW per hour. Scheduling changes 

will be permitted up to twenty (20) 

minutes [or a reasonable time that is 

generally accepted in the region and is 

consistently adhered to by the 

Transmission Provider] before the start 

of the next clock hour provided that the 

Delivering Party and Receiving Party 

also agree to the schedule modification. 

The Transmission Provider will furnish 

to the Delivering Party’s system 

operator, hour-to-hour schedules equal 

to those furnished by the Receiving 

Party (unless reduced for losses) and 

shall deliver the capacity and energy 

provided by such schedules. Should the 

Transmission Customer, Delivering 

Party or Receiving Party revise or 

terminate any schedule, such party shall 

immediately notify the Transmission 

Provider, and the Transmission Provider 

shall have the right to adjust 

accordingly the schedule for capacity 

and energy to be received and to be 

delivered. 

14.7 Curtailment or Interruption of 

Service 

The Transmission Provider reserves 

the right to Curtail, in whole or in part, 

Non-Firm Point-To-Point Transmission 

Service provided under the Tariff for 

reliability reasons when an emergency 

or other unforeseen condition threatens 

to impair or degrade the reliability of its 

Transmission System or the systems 

directly and indirectly interconnected 

with Transmission Provider’s 

Transmission System. Transmission 

Provider may elect to implement such 

Curtailments pursuant to the 

Transmission Loading Relief procedures 

specified in Attachment J. The 

Transmission Provider reserves the right 

to Interrupt, in whole or in part, NonFirm Point-To-Point Transmission 

Service provided under the Tariff for 

economic reasons in order to 

accommodate (1) a request for Firm 

Transmission Service, (2) a request for 

Non-Firm Point-To-Point Transmission 

Service of greater duration, (3) a request 

for Non-Firm Point-To-Point 

Transmission Service of equal duration 

with a higher price, (4) transmission 

service for Network Customers from 

non-designated resources, or (5) 

transmission service for Firm Point-toPoint Transmission Service during 

conditional curtailment periods as 

described in Section 15.4. The 

Transmission Provider also will 

discontinue or reduce service to the 

Transmission Customer to the extent 

that deliveries for transmission are 

discontinued or reduced at the Point(s) 

of Receipt. Where required, 

Curtailments or Interruptions will be 

made on a non-discriminatory basis to 

the transaction(s) that effectively relieve 

the constraint, however, Non-Firm 

Point-To-Point Transmission Service 

shall be subordinate to Firm 

Transmission Service. If multiple 

transactions require Curtailment or 

Interruption, to the extent practicable 

and consistent with Good Utility 

Practice, Curtailments or Interruptions 

will be made to transactions of the 

shortest term (e.g., hourly non-firm 

transactions will be Curtailed or 

Interrupted before daily non-firm 

transactions and daily non-firm 

transactions will be Curtailed or 

Interrupted before weekly non-firm 

transactions). Transmission service for 

Network Customers from resources 

other than designated Network 

Resources will have a higher priority 

than any Non-Firm Point-To-Point 

Transmission Service under the Tariff. 

Non-Firm Point-To-Point Transmission 

Service over secondary Point(s) of 

Receipt and Point(s) of Delivery will 

have a lower priority than any Non-Firm 

Point-To-Point Transmission Service 

under the Tariff. The Transmission 

Provider will provide advance notice of 

Curtailment or Interruption where such 


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12514 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

notice can be provided consistent with 

Good Utility Practice. 

15 Service Availability 

15.1 General Conditions 

The Transmission Provider will 

provide Firm and Non-Firm Point-ToPoint Transmission Service over, on or 

across its Transmission System to any 

Transmission Customer that has met the 

requirements of Section 16. 

15.2 Determination of Available 

Transfer Capability 

A description of the Transmission 

Provider’s specific methodology for 

assessing available transfer capability 

posted on the Transmission Provider’s 

OASIS (Section 4) is contained in 

Attachment C of the Tariff. In the event 

sufficient transfer capability may not 

exist to accommodate a service request, 

the Transmission Provider will respond 

by performing a System Impact Study. 

15.3 Initiating Service in the Absence 

of an Executed Service Agreement 

If the Transmission Provider and the 

Transmission Customer requesting Firm 

or Non-Firm Point-To-Point 

Transmission Service cannot agree on 

all the terms and conditions of the 

Point-To-Point Service Agreement, the 

Transmission Provider shall file with 

the Commission, within thirty (30) days 

after the date the Transmission 

Customer provides written notification 

directing the Transmission Provider to 

file, an unexecuted Point-To-Point 

Service Agreement containing terms and 

conditions deemed appropriate by the 

Transmission Provider for such 

requested Transmission Service. The 

Transmission Provider shall commence 

providing Transmission Service subject 

to the Transmission Customer agreeing 

to (i) compensate the Transmission 

Provider at whatever rate the 

Commission ultimately determines to be 

just and reasonable, and (ii) comply 

with the terms and conditions of the 

Tariff including posting appropriate 

security deposits in accordance with the 

terms of Section 17.3. 

15.4 Obligation To Provide 

Transmission Service That Requires 

Expansion or Modification of the 

Transmission System, Redispatch or 

Conditional Curtailment 

(a) If the Transmission Provider 

determines that it cannot accommodate 

a Completed Application for Firm PointTo-Point Transmission Service because 

of insufficient capability on its 

Transmission System, the Transmission 

Provider will use due diligence to 

expand or modify its Transmission 

System to provide the requested Firm 

Transmission Service, consistent with 

its planning obligations in Attachment 

K, provided the Transmission Customer 

agrees to compensate the Transmission 

Provider for such costs pursuant to the 

terms of Section 27. The Transmission 

Provider will conform to Good Utility 

Practice and its planning obligations in 

Attachment K, in determining the need 

for new facilities and in the design and 

construction of such facilities. The 

obligation applies only to those facilities 

that the Transmission Provider has the 

right to expand or modify. 

(b) If the Transmission Provider 

determines that it cannot accommodate 

a Completed Application for Firm PointTo-Point Transmission Service because 

of insufficient capability on its 

Transmission System, the Transmission 

Provider will use due diligence to 

provide redispatch from its own 

resources until (i) Network Upgrades are 

completed for the Transmission 

Customer, (ii) the Transmission 

Provider determines through a biennial 

reassessment that it can no longer 

reliably provide the redispatch, or (iii) 

the Transmission Customer terminates 

the service because of redispatch 

changes resulting from the 

reassessment. A Transmission Provider 

shall not unreasonably deny selfprovided redispatch or redispatch 

arranged by the Transmission Customer 

from a third party resource. 

(c) If the Transmission Provider 

determines that it cannot accommodate 

a Completed Application for Firm PointTo-Point Transmission Service because 

of insufficient capability on its 

Transmission System, the Transmission 

Provider will offer the Firm 

Transmission Service with the 

condition that the Transmission 

Provider may curtail the service prior to 

the curtailment of other Firm 

Transmission Service for a specified 

number of hours per year or during 

System Condition(s). If the 

Transmission Customer accepts the 

service, the Transmission Provider will 

use due diligence to provide the service 

until (i) Network Upgrades are 

completed for the Transmission 

Customer, (ii) the Transmission 

Provider determines through a biennial 

reassessment that it can no longer 

reliably provide such service, or (iii) the 

Transmission Customer terminates the 

service because the reassessment 

increased the number of hours per year 

of conditional curtailment or changed 

the System Conditions. 

15.5 Deferral of Service 

The Transmission Provider may defer 

providing service until it completes 

construction of new transmission 

facilities or upgrades needed to provide 

Firm Point-To-Point Transmission 

Service whenever the Transmission 

Provider determines that providing the 

requested service would, without such 

new facilities or upgrades, impair or 

degrade reliability to any existing firm 

services. 

15.6 Other Transmission Service 

Schedules 

Eligible Customers receiving 

transmission service under other 

agreements on file with the Commission 

may continue to receive transmission 

service under those agreements until 

such time as those agreements may be 

modified by the Commission. 

15.7 Real Power Losses 

Real Power Losses are associated with 

all transmission service. The 

Transmission Provider is not obligated 

to provide Real Power Losses. The 

Transmission Customer is responsible 

for replacing losses associated with all 

transmission service as calculated by 

the Transmission Provider. The 

applicable Real Power Loss factors are 

as follows: [To be completed by the 

Transmission Provider]. 

16 Transmission Customer 

Responsibilities 

16.1 Conditions Required of 

Transmission Customers 

Point-To-Point Transmission Service 

shall be provided by the Transmission 

Provider only if the following 

conditions are satisfied by the 

Transmission Customer: 

(a) The Transmission Customer has 

pending a Completed Application for 

service; 

(b) The Transmission Customer meets 

the creditworthiness criteria set forth in 

Section 11; 

(c) The Transmission Customer will 

have arrangements in place for any 

other transmission service necessary to 

effect the delivery from the generating 

source to the Transmission Provider 

prior to the time service under Part II of 

the Tariff commences; 

(d) The Transmission Customer agrees 

to pay for any facilities constructed and 

chargeable to such Transmission 

Customer under Part II of the Tariff, 

whether or not the Transmission 

Customer takes service for the full term 

of its reservation; 

(e) The Transmission Customer 

provides the information required by 

the Transmission Provider’s planning 

process established in Attachment K; 

and 

(f) The Transmission Customer has 

executed a Point-To-Point Service 


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Agreement or has agreed to receive 

service pursuant to Section 15.3. 

16.2 Transmission Customer 

Responsibility for Third-Party 

Arrangements 

Any scheduling arrangements that 

may be required by other electric 

systems shall be the responsibility of the 

Transmission Customer requesting 

service. The Transmission Customer 

shall provide, unless waived by the 

Transmission Provider, notification to 

the Transmission Provider identifying 

such systems and authorizing them to 

schedule the capacity and energy to be 

transmitted by the Transmission 

Provider pursuant to Part II of the Tariff 

on behalf of the Receiving Party at the 

Point of Delivery or the Delivering Party 

at the Point of Receipt. However, the 

Transmission Provider will undertake 

reasonable efforts to assist the 

Transmission Customer in making such 

arrangements, including without 

limitation, providing any information or 

data required by such other electric 

system pursuant to Good Utility 

Practice. 

17 Procedures for Arranging Firm 

Point-To-Point Transmission Service 

17.1 Application 

A request for Firm Point-To-Point 

Transmission Service for periods of one 

year or longer must contain a written 

Application to: [Transmission Provider 

Name and Address], at least sixty (60) 

days in advance of the calendar month 

in which service is to commence. The 

Transmission Provider will consider 

requests for such firm service on shorter 

notice when feasible. Requests for firm 

service for periods of less than one year 

shall be subject to expedited procedures 

that shall be negotiated between the 

Parties within the time constraints 

provided in Section 17.5. All Firm 

Point-To-Point Transmission Service 

requests should be submitted by 

entering the information listed below on 

the Transmission Provider’s OASIS. 

Prior to implementation of the 

Transmission Provider’s OASIS, a 

Completed Application may be 

submitted by (i) transmitting the 

required information to the 

Transmission Provider by telefax, or (ii) 

providing the information by telephone 

over the Transmission Provider’s time 

recorded telephone line. Each of these 

methods will provide a time-stamped 

record for establishing the priority of the 

Application. 

17.2 Completed Application 

A Completed Application shall 

provide all of the information included 

in 18 CFR 2.20 including but not limited 

to the following: 

(i) The identity, address, telephone 

number and facsimile number of the 

entity requesting service; 

(ii) A statement that the entity 

requesting service is, or will be upon 

commencement of service, an Eligible 

Customer under the Tariff; 

(iii) The location of the Point(s) of 

Receipt and Point(s) of Delivery and the 

identities of the Delivering Parties and 

the Receiving Parties; 

(iv) The location of the generating 

facility(ies) supplying the capacity and 

energy and the location of the load 

ultimately served by the capacity and 

energy transmitted. The Transmission 

Provider will treat this information as 

confidential except to the extent that 

disclosure of this information is 

required by this Tariff, by regulatory or 

judicial order, for reliability purposes 

pursuant to Good Utility Practice or 

pursuant to RTG transmission 

information sharing agreements. The 

Transmission Provider shall treat this 

information consistent with the 

standards of conduct contained in Part 

37 of the Commission’s regulations; 

(v) A description of the supply 

characteristics of the capacity and 

energy to be delivered; 

(vi) An estimate of the capacity and 

energy expected to be delivered to the 

Receiving Party; 

(vii) The Service Commencement Date 

and the term of the requested 

Transmission Service; 

(viii) The transmission capacity 

requested for each Point of Receipt and 

each Point of Delivery on the 

Transmission Provider’s Transmission 

System; customers may combine their 

requests for service in order to satisfy 

the minimum transmission capacity 

requirement; 

(ix) A statement indicating whether 

the Transmission Customer commits to 

a Pre-Confirmed Request, i.e., will 

execute a Service Agreement upon 

receipt of notification that the 

Transmission Provider can provide the 

requested Transmission Service; and 

(x) Any additional information 

required by the Transmission Provider’s 

planning process established in 

Attachment K. 

The Transmission Provider shall treat 

this information consistent with the 

standards of conduct contained in Part 

37 of the Commission’s regulations. 

17.3 Deposit 

A Completed Application for Firm 

Point-To-Point Transmission Service 

also shall include a deposit of either one 

month’s charge for Reserved Capacity or 

the full charge for Reserved Capacity for 

service requests of less than one month. 

If the Application is rejected by the 

Transmission Provider because it does 

not meet the conditions for service as 

set forth herein, or in the case of 

requests for service arising in 

connection with losing bidders in a 

Request For Proposals (RFP), said 

deposit shall be returned with interest 

less any reasonable costs incurred by 

the Transmission Provider in 

connection with the review of the losing 

bidder’s Application. The deposit also 

will be returned with interest less any 

reasonable costs incurred by the 

Transmission Provider if the 

Transmission Provider is unable to 

complete new facilities needed to 

provide the service. If an Application is 

withdrawn or the Eligible Customer 

decides not to enter into a Service 

Agreement for Firm Point-To-Point 

Transmission Service, the deposit shall 

be refunded in full, with interest, less 

reasonable costs incurred by the 

Transmission Provider to the extent 

such costs have not already been 

recovered by the Transmission Provider 

from the Eligible Customer. The 

Transmission Provider will provide to 

the Eligible Customer a complete 

accounting of all costs deducted from 

the refunded deposit, which the Eligible 

Customer may contest if there is a 

dispute concerning the deducted costs. 

Deposits associated with construction of 

new facilities are subject to the 

provisions of Section 19. If a Service 

Agreement for Firm Point-To-Point 

Transmission Service is executed, the 

deposit, with interest, will be returned 

to the Transmission Customer upon 

expiration or termination of the Service 

Agreement for Firm Point-To-Point 

Transmission Service. Applicable 

interest shall be computed in 

accordance with the Commission’s 

regulations at 18 CFR 35.19a(a)(2)(iii), 

and shall be calculated from the day the 

deposit check is credited to the 

Transmission Provider’s account. 

17.4 Notice of Deficient Application 

If an Application fails to meet the 

requirements of the Tariff, the 

Transmission Provider shall notify the 

entity requesting service within fifteen 

(15) days of receipt of the reasons for 

such failure. The Transmission Provider 

will attempt to remedy minor 

deficiencies in the Application through 

informal communications with the 

Eligible Customer. If such efforts are 

unsuccessful, the Transmission Provider 

shall return the Application, along with 

any deposit, with interest. Upon receipt 

of a new or revised Application that 

fully complies with the requirements of 

Part II of the Tariff, the Eligible 


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Customer shall be assigned a new 

priority consistent with the date of the 

new or revised Application. 

17.5 Response to a Completed 

Application 

Following receipt of a Completed 

Application for Firm Point-To-Point 

Transmission Service, the Transmission 

Provider shall make a determination of 

available transfer capability as required 

in Section 15.2. The Transmission 

Provider shall notify the Eligible 

Customer as soon as practicable, but not 

later than thirty (30) days after the date 

of receipt of a Completed Application 

either (i) if it will be able to provide 

service without performing a System 

Impact Study or (ii) if such a study is 

needed to evaluate the impact of the 

Application pursuant to Section 19.1. 

Responses by the Transmission Provider 

must be made as soon as practicable to 

all completed applications (including 

applications by its own merchant 

function) and the timing of such 

responses must be made on a nondiscriminatory basis. 

17.6 Execution of Service Agreement 

Whenever the Transmission Provider 

determines that a System Impact Study 

is not required and that the service can 

be provided, it shall notify the Eligible 

Customer as soon as practicable but no 

later than thirty (30) days after receipt 

of the Completed Application. Where a 

System Impact Study is required, the 

provisions of Section 19 will govern the 

execution of a Service Agreement. 

Failure of an Eligible Customer to 

execute and return the Service 

Agreement or request the filing of an 

unexecuted service agreement pursuant 

to Section 15.3, within fifteen (15) days 

after it is tendered by the Transmission 

Provider will be deemed a withdrawal 

and termination of the Application and 

any deposit submitted shall be refunded 

with interest. Nothing herein limits the 

right of an Eligible Customer to file 

another Application after such 

withdrawal and termination. 

17.7 Extensions for Commencement of 

Service 

The Transmission Customer can 

obtain up to five (5) one-year extensions 

for the commencement of service. The 

Transmission Customer may postpone 

service by paying a non-refundable 

annual reservation fee equal to onemonth’s charge for Firm Transmission 

Service for each year or fraction thereof. 

If the Eligible Customer does not pay 

this non-refundable reservation fee 

within 15 days of notifying the 

Transmission Provider it intends to 

extend the commencement of service, 

then the Eligible Customer’s application 

shall be deemed withdrawn and its 

deposit, pursuant to Section 17.3, shall 

be returned with interest. If during any 

extension for the commencement of 

service an Eligible Customer submits a 

Completed Application for Firm 

Transmission Service, and such request 

can be satisfied only by releasing all or 

part of the Transmission Customer’s 

Reserved Capacity, the original 

Reserved Capacity will be released 

unless the following condition is 

satisfied. Within thirty (30) days, the 

original Transmission Customer agrees 

to pay the Firm Point-To-Point 

transmission rate for its Reserved 

Capacity concurrent with the new 

Service Commencement Date. In the 

event the Transmission Customer elects 

to release the Reserved Capacity, the 

reservation fees or portions thereof 

previously paid will be forfeited. 

18 Procedures for Arranging Non-Firm 

Point-To-Point Transmission Service 

18.1 Application 

Eligible Customers seeking Non-Firm 

Point-To-Point Transmission Service 

must submit a Completed Application 

to the Transmission Provider. 

Applications should be submitted by 

entering the information listed below on 

the Transmission Provider’s OASIS. 

Prior to implementation of the 

Transmission Provider’s OASIS, a 

Completed Application may be 

submitted by (i) transmitting the 

required information to the 

Transmission Provider by telefax, or (ii) 

providing the information by telephone 

over the Transmission Provider’s time 

recorded telephone line. Each of these 

methods will provide a time-stamped 

record for establishing the service 

priority of the Application. 

18.2 Completed Application 

A Completed Application shall 

provide all of the information included 

in 18 CFR 2.20 including but not limited 

to the following: 

(i) The identity, address, telephone 

number and facsimile number of the 

entity requesting service; 

(ii) A statement that the entity 

requesting service is, or will be upon 

commencement of service, an Eligible 

Customer under the Tariff; 

(iii) The Point(s) of Receipt and the 

Point(s) of Delivery; 

(iv) The maximum amount of capacity 

requested at each Point of Receipt and 

Point of Delivery; and 

(v) The proposed dates and hours for 

initiating and terminating transmission 

service hereunder. 

In addition to the information 

specified above, when required to 

properly evaluate system conditions, the 

Transmission Provider also may ask the 

Transmission Customer to provide the 

following: 

(vi) The electrical location of the 

initial source of the power to be 

transmitted pursuant to the 

Transmission Customer’s request for 

service; and 

(vii) The electrical location of the 

ultimate load. 

The Transmission Provider will treat 

this information in (vi) and (vii) as 

confidential at the request of the 

Transmission Customer except to the 

extent that disclosure of this 

information is required by this Tariff, by 

regulatory or judicial order, for 

reliability purposes pursuant to Good 

Utility Practice, or pursuant to RTG 

transmission information sharing 

agreements. The Transmission Provider 

shall treat this information consistent 

with the standards of conduct contained 

in Part 37 of the Commission’s 

regulations. 

(viii) A statement indicating whether 

the Transmission Customer commits to 

a Pre-Confirmed Request, i.e., will 

execute a Service Agreement upon 

receipt of notification that the 

Transmission Provider can provide the 

requested Transmission Service. 

18.3 Reservation of Non-Firm Point-toPoint Transmission Service 

Requests for monthly service shall be 

submitted no earlier than sixty (60) days 

before service is to commence; requests 

for weekly service shall be submitted no 

earlier than fourteen (14) days before 

service is to commence, requests for 

daily service shall be submitted no 

earlier than two (2) days before service 

is to commence, and requests for hourly 

service shall be submitted no earlier 

than noon the day before service is to 

commence. Requests for service 

received later than 2 p.m. prior to the 

day service is scheduled to commence 

will be accommodated if practicable [or 

such reasonable times that are generally 

accepted in the region and are 

consistently adhered to by the 

Transmission Provider]. 

18.4 Determination of Available 

Transfer Capability 

Following receipt of a tendered 

schedule the Transmission Provider will 

make a determination on a nondiscriminatory basis of available transfer 

capability pursuant to Section 15.2. 

Such determination shall be made as 

soon as reasonably practicable after 

receipt, but not later than the following 

time periods for the following terms of 

service (i) thirty (30) minutes for hourly 

service, (ii) thirty (30) minutes for daily 


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service, (iii) four (4) hours for weekly 

service, and (iv) two (2) days for 

monthly service. [Or such reasonable 

times that are generally accepted in the 

region and are consistently adhered to 

by the Transmission Provider]. 

19 Additional Study Procedures for 

Firm Point-to-Point Transmission 

Service Requests 

19.1 Notice of Need for System Impact 

Study 

After receiving a request for service, 

the Transmission Provider shall 

determine on a non-discriminatory basis 

whether a System Impact Study is 

needed. A description of the 

Transmission Provider’s methodology 

for completing a System Impact Study is 

provided in Attachment D. If the 

Transmission Provider determines that a 

System Impact Study is necessary to 

accommodate the requested service, it 

shall so inform the Eligible Customer, as 

soon as practicable. Once informed, the 

Eligible Customer shall timely notify the 

Transmission Provider if it elects not to 

have the Transmission Provider study 

redispatch or conditional curtailment as 

part of the System Impact Study. If 

notification is provided prior to tender 

of the System Impact Study Agreement, 

the Eligible Customer can avoid the 

costs associated with the study of these 

options. The Transmission Provider 

shall within thirty (30) days of receipt 

of a Completed Application, tender a 

System Impact Study Agreement 

pursuant to which the Eligible Customer 

shall agree to reimburse the 

Transmission Provider for performing 

the required System Impact Study. For 

a service request to remain a Completed 

Application, the Eligible Customer shall 

execute the System Impact Study 

Agreement and return it to the 

Transmission Provider within fifteen 

(15) days. If the Eligible Customer elects 

not to execute the System Impact Study 

Agreement, its application shall be 

deemed withdrawn and its deposit, 

pursuant to Section 17.3, shall be 

returned with interest. 

19.2 System Impact Study Agreement 

and Cost Reimbursement 

(i) The System Impact Study 

Agreement will clearly specify the 

Transmission Provider’s estimate of the 

actual cost, and time for completion of 

the System Impact Study. The charge 

shall not exceed the actual cost of the 

study. In performing the System Impact 

Study, the Transmission Provider shall 

rely, to the extent reasonably 

practicable, on existing transmission 

planning studies. The Eligible Customer 

will not be assessed a charge for such 

existing studies; however, the Eligible 

Customer will be responsible for charges 

associated with any modifications to 

existing planning studies that are 

reasonably necessary to evaluate the 

impact of the Eligible Customer’s 

request for service on the Transmission 

System. 

(ii) If in response to multiple Eligible 

Customers requesting service in relation 

to the same competitive solicitation, a 

single System Impact Study is sufficient 

for the Transmission Provider to 

accommodate the requests for service, 

the costs of that study shall be pro-rated 

among the Eligible Customers. 

(iii) For System Impact Studies that 

the Transmission Provider conducts on 

its own behalf, the Transmission 

Provider shall record the cost of the 

System Impact Studies pursuant to 

Section 20. 

19.3 System Impact Study Procedures 

Upon receipt of an executed System 

Impact Study Agreement, the 

Transmission Provider will use due 

diligence to complete the required 

System Impact Study within a sixty (60) 

day period. The System Impact Study 

shall identify (1) any system constraints, 

identified with specificity by 

transmission element or flowgate, (2) 

redispatch options (when requested by 

a Transmission Customer) including an 

estimate of the cost of redispatch, (3) 

conditional curtailment options (when 

requested by a Transmission Customer) 

including the number of hours per year 

and the System Conditions during 

which conditional curtailment may 

occur, and (4) additional Direct 

Assignment Facilities or Network 

Upgrades required to provide the 

requested service. For customers 

requesting the study of redispatch 

options, the System Impact Study shall 

(1) identify all resources located within 

the Transmission Provider’s Control 

Area that can significantly contribute 

toward relieving the system constraint 

and (2) provide a measurement of each 

resource’s impact on the system 

constraint. If the Transmission Provider 

possesses information indicating that 

any resource outside its Control Area 

could relieve the constraint, it shall 

identify each such resource in the 

System Impact Study. In the event that 

the Transmission Provider is unable to 

complete the required System Impact 

Study within such time period, it shall 

so notify the Eligible Customer and 

provide an estimated completion date 

along with an explanation of the reasons 

why additional time is required to 

complete the required studies. A copy of 

the completed System Impact Study and 

related work papers shall be made 

available to the Eligible Customer as 

soon as the System Impact Study is 

complete. The Transmission Provider 

will use the same due diligence in 

completing the System Impact Study for 

an Eligible Customer as it uses when 

completing studies for itself. The 

Transmission Provider shall notify the 

Eligible Customer immediately upon 

completion of the System Impact Study 

if the Transmission System will be 

adequate to accommodate all or part of 

a request for service or that no costs are 

likely to be incurred for new 

transmission facilities or upgrades. In 

order for a request to remain a 

Completed Application, within fifteen 

(15) days of completion of the System 

Impact Study the Eligible Customer 

must execute a Service Agreement or 

request the filing of an unexecuted 

Service Agreement pursuant to Section 

15.3, or the Application shall be deemed 

terminated and withdrawn. 

19.4 Facilities Study Procedures 

If a System Impact Study indicates 

that additions or upgrades to the 

Transmission System are needed to 

supply the Eligible Customer’s service 

request, the Transmission Provider, 

within thirty (30) days of the 

completion of the System Impact Study, 

shall tender to the Eligible Customer a 

Facilities Study Agreement pursuant to 

which the Eligible Customer shall agree 

to reimburse the Transmission Provider 

for performing the required Facilities 

Study. For a service request to remain 

a Completed Application, the Eligible 

Customer shall execute the Facilities 

Study Agreement and return it to the 

Transmission Provider within fifteen 

(15) days. If the Eligible Customer elects 

not to execute the Facilities Study 

Agreement, its application shall be 

deemed withdrawn and its deposit, 

pursuant to Section 17.3, shall be 

returned with interest. Upon receipt of 

an executed Facilities Study Agreement, 

the Transmission Provider will use due 

diligence to complete the required 

Facilities Study within a sixty (60) day 

period. If the Transmission Provider is 

unable to complete the Facilities Study 

in the allotted time period, the 

Transmission Provider shall notify the 

Transmission Customer and provide an 

estimate of the time needed to reach a 

final determination along with an 

explanation of the reasons that 

additional time is required to complete 

the study. When completed, the 

Facilities Study will include a good 

faith estimate of (i) the cost of Direct 

Assignment Facilities to be charged to 

the Transmission Customer, (ii) the 

Transmission Customer’s appropriate 

share of the cost of any required 


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Network Upgrades as determined 

pursuant to the provisions of Part II of 

the Tariff, and (iii) the time required to 

complete such construction and initiate 

the requested service. The Transmission 

Customer shall provide the 

Transmission Provider with a letter of 

credit or other reasonable form of 

security acceptable to the Transmission 

Provider equivalent to the costs of new 

facilities or upgrades consistent with 

commercial practices as established by 

the Uniform Commercial Code. The 

Transmission Customer shall have thirty 

(30) days to execute a Service 

Agreement or request the filing of an 

unexecuted Service Agreement and 

provide the required letter of credit or 

other form of security or the request will 

no longer be a Completed Application 

and shall be deemed terminated and 

withdrawn. 

19.5 Facilities Study Modifications 

Any change in design arising from 

inability to site or construct facilities as 

proposed will require development of a 

revised good faith estimate. New good 

faith estimates also will be required in 

the event of new statutory or regulatory 

requirements that are effective before 

the completion of construction or other 

circumstances beyond the control of the 

Transmission Provider that significantly 

affect the final cost of new facilities or 

upgrades to be charged to the 

Transmission Customer pursuant to the 

provisions of Part II of the Tariff. 

19.6 Due Diligence in Completing New 

Facilities 

The Transmission Provider shall use 

due diligence to add necessary facilities 

or upgrade its Transmission System 

within a reasonable time. The 

Transmission Provider will not upgrade 

its existing or planned Transmission 

System in order to provide the 

requested Firm Point-To-Point 

Transmission Service if doing so would 

impair system reliability or otherwise 

impair or degrade existing firm service. 

19.7 Partial Interim Service 

If the Transmission Provider 

determines that it will not have 

adequate transfer capability to satisfy 

the full amount of a Completed 

Application for Firm Point-To-Point 

Transmission Service, the Transmission 

Provider nonetheless shall be obligated 

to offer and provide the portion of the 

requested Firm Point-To-Point 

Transmission Service that can be 

accommodated without addition of any 

facilities and through redispatch. 

However, the Transmission Provider 

shall not be obligated to provide the 

incremental amount of requested Firm 

Point-To-Point Transmission Service 

that requires the addition of facilities or 

upgrades to the Transmission System 

until such facilities or upgrades have 

been placed in service. 

19.8 Expedited Procedures for New 

Facilities 

In lieu of the procedures set forth 

above, the Eligible Customer shall have 

the option to expedite the process by 

requesting the Transmission Provider to 

tender at one time, together with the 

results of required studies, an 

‘‘Expedited Service Agreement’’

pursuant to which the Eligible Customer 

would agree to compensate the 

Transmission Provider for all costs 

incurred pursuant to the terms of the 

Tariff. In order to exercise this option, 

the Eligible Customer shall request in 

writing an expedited Service Agreement 

covering all of the above-specified items 

within thirty (30) days of receiving the 

results of the System Impact Study 

identifying needed facility additions or 

upgrades or costs incurred in providing 

the requested service. While the 

Transmission Provider agrees to provide 

the Eligible Customer with its best 

estimate of the new facility costs and 

other charges that may be incurred, such 

estimate shall not be binding and the 

Eligible Customer must agree in writing 

to compensate the Transmission 

Provider for all costs incurred pursuant 

to the provisions of the Tariff. The 

Eligible Customer shall execute and 

return such an Expedited Service 

Agreement within fifteen (15) days of its 

receipt or the Eligible Customer’s 

request for service will cease to be a 

Completed Application and will be 

deemed terminated and withdrawn. 

19.9 Penalties for Failure To Meet 

Study Deadlines 

Sections 19.3 and 19.4 require a 

Transmission Provider to use due 

diligence to meet 60-day study 

completion deadlines for System Impact 

Studies and Facilities Studies. 

(i) The Transmission Provider is 

required to file a notice with the 

Commission in the event that more than 

twenty (20) percent of non-Affiliates’

System Impact Studies and Facilities 

Studies completed by the Transmission 

Provider in any two consecutive 

calendar quarters are not completed 

within the 60-day study completion 

deadlines. Such notice must be filed 

within thirty (30) days of the end of the 

calendar quarter triggering the notice 

requirement. 

(ii) For the purposes of calculating the 

percent of non-Affiliates’ System Impact 

Studies and Facilities Studies processed 

outside of the 60-day study completion 

deadlines, the Transmission Provider 

shall consider all System Impact Studies 

and Facilities Studies that it completes 

for non-Affiliates during the calendar 

quarter. The percentage should be 

calculated by dividing the number of 

those studies which are completed on 

time by the total number of completed 

studies. The Transmission Provider may 

provide an explanation in its 

notification filing to the Commission if 

it believes there are extenuating 

circumstances that prevented it from 

meeting the 60-day study completion 

deadlines. 

(iii) The Transmission Provider is 

subject to an operational penalty if it 

completes ten (10) percent or more of 

non-Affiliates’ System Impact Studies 

and Facilities Studies outside of the 60- 

day study completion deadlines for each 

of the two calendar quarters 

immediately following the quarter that 

triggered its notification filing to the 

Commission. The operational penalty 

will be assessed for each calendar 

quarter for which an operational penalty 

applies, starting with the calendar 

quarter immediately following the 

quarter that triggered the Transmission 

Provider’s notification filing to the 

Commission. The operational penalty 

will continue to be assessed each 

quarter until the Transmission Provider 

completes at least ninety (90) percent of 

all non-Affiliates’ System Impact 

Studies and Facilities Studies within 

the 60-day deadline. 

(iv) For penalties assessed in 

accordance with subsection (iii) above, 

the penalty amount for each System 

Impact Study or Facilities Study shall 

be equal to $500 for each day the 

Transmission Provider takes to 

complete that study beyond the 60-day 

deadline. 

20 Procedures if the Transmission 

Provider Is Unable To Complete New 

Transmission Facilities for Firm Pointto-Point Transmission Service 

20.1 Delays in Construction of New 

Facilities 

If any event occurs that will 

materially affect the time for completion 

of new facilities, or the ability to 

complete them, the Transmission 

Provider shall promptly notify the 

Transmission Customer. In such 

circumstances, the Transmission 

Provider shall within thirty (30) days of 

notifying the Transmission Customer of 

such delays, convene a technical 

meeting with the Transmission 

Customer to evaluate the alternatives 

available to the Transmission Customer. 

The Transmission Provider also shall 

make available to the Transmission 


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Customer studies and work papers 

related to the delay, including all 

information that is in the possession of 

the Transmission Provider that is 

reasonably needed by the Transmission 

Customer to evaluate any alternatives. 

20.2 Alternatives to the Original 

Facility Additions 

When the review process of Section 

20.1 determines that one or more 

alternatives exist to the originally 

planned construction project, the 

Transmission Provider shall present 

such alternatives for consideration by 

the Transmission Customer. If, upon 

review of any alternatives, the 

Transmission Customer desires to 

maintain its Completed Application 

subject to construction of the alternative 

facilities, it may request the 

Transmission Provider to submit a 

revised Service Agreement for Firm 

Point-To-Point Transmission Service. If 

the alternative approach solely involves 

Non-Firm Point-To-Point Transmission 

Service, the Transmission Provider shall 

promptly tender a Service Agreement 

for Non-Firm Point-To-Point 

Transmission Service providing for the 

service. In the event the Transmission 

Provider concludes that no reasonable 

alternative exists and the Transmission 

Customer disagrees, the Transmission 

Customer may seek relief under the 

dispute resolution procedures pursuant 

to Section 12 or it may refer the dispute 

to the Commission for resolution. 

20.3 Refund Obligation for Unfinished 

Facility Additions 

If the Transmission Provider and the 

Transmission Customer mutually agree 

that no other reasonable alternatives 

exist and the requested service cannot 

be provided out of existing capability 

under the conditions of Part II of the 

Tariff, the obligation to provide the 

requested Firm Point-To-Point 

Transmission Service shall terminate 

and any deposit made by the 

Transmission Customer shall be 

returned with interest pursuant to 

Commission regulations 

35.19a(a)(2)(iii). However, the 

Transmission Customer shall be 

responsible for all prudently incurred 

costs by the Transmission Provider 

through the time construction was 

suspended. 

21 Provisions Relating to Transmission 

Construction and Services on the 

Systems of Other Utilities 

21.1 Responsibility for Third-Party 

System Additions 

The Transmission Provider shall not 

be responsible for making arrangements 

for any necessary engineering, 

permitting, and construction of 

transmission or distribution facilities on 

the system(s) of any other entity or for 

obtaining any regulatory approval for 

such facilities. The Transmission 

Provider will undertake reasonable 

efforts to assist the Transmission 

Customer in obtaining such 

arrangements, including without 

limitation, providing any information or 

data required by such other electric 

system pursuant to Good Utility 

Practice. 

21.2 Coordination of Third-Party 

System Additions 

In circumstances where the need for 

transmission facilities or upgrades is 

identified pursuant to the provisions of 

Part II of the Tariff, and if such upgrades 

further require the addition of 

transmission facilities on other systems, 

the Transmission Provider shall have 

the right to coordinate construction on 

its own system with the construction 

required by others. The Transmission 

Provider, after consultation with the 

Transmission Customer and 

representatives of such other systems, 

may defer construction of its new 

transmission facilities, if the new 

transmission facilities on another 

system cannot be completed in a timely 

manner. The Transmission Provider 

shall notify the Transmission Customer 

in writing of the basis for any decision 

to defer construction and the specific 

problems which must be resolved before 

it will initiate or resume construction of 

new facilities. Within sixty (60) days of 

receiving written notification by the 

Transmission Provider of its intent to 

defer construction pursuant to this 

section, the Transmission Customer may 

challenge the decision in accordance 

with the dispute resolution procedures 

pursuant to Section 12 or it may refer 

the dispute to the Commission for 

resolution. 

22 Changes in Service Specifications 

22.1 Modifications On a Non-Firm 

Basis 

The Transmission Customer taking 

Firm Point-To-Point Transmission 

Service may request the Transmission 

Provider to provide transmission service 

on a non-firm basis over Receipt and 

Delivery Points other than those 

specified in the Service Agreement 

(‘‘Secondary Receipt and Delivery 

Points’’), in amounts not to exceed its 

firm capacity reservation, without 

incurring an additional Non-Firm PointTo-Point Transmission Service charge or 

executing a new Service Agreement, 

subject to the following conditions. 

(a) Service provided over Secondary 

Receipt and Delivery Points will be nonfirm only, on an as-available basis and 

will not displace any firm or non-firm 

service reserved or scheduled by thirdparties under the Tariff or by the 

Transmission Provider on behalf of its 

Native Load Customers. 

(b) The sum of all Firm and non-firm 

Point-To-Point Transmission Service 

provided to the Transmission Customer 

at any time pursuant to this section 

shall not exceed the Reserved Capacity 

in the relevant Service Agreement under 

which such services are provided. 

(c) The Transmission Customer shall 

retain its right to schedule Firm PointTo-Point Transmission Service at the 

Receipt and Delivery Points specified in 

the relevant Service Agreement in the 

amount of its original capacity 

reservation. 

(d) Service over Secondary Receipt 

and Delivery Points on a non-firm basis 

shall not require the filing of an 

Application for Non-Firm Point-ToPoint Transmission Service under the 

Tariff. However, all other requirements 

of Part II of the Tariff (except as to 

transmission rates) shall apply to 

transmission service on a non-firm basis 

over Secondary Receipt and Delivery 

Points. 

22.2 Modification On a Firm Basis 

Any request by a Transmission 

Customer to modify Receipt and 

Delivery Points on a firm basis shall be 

treated as a new request for service in 

accordance with Section 17 hereof, 

except that such Transmission Customer 

shall not be obligated to pay any 

additional deposit if the capacity 

reservation does not exceed the amount 

reserved in the existing Service 

Agreement. While such new request is 

pending, the Transmission Customer 

shall retain its priority for service at the 

existing firm Receipt and Delivery 

Points specified in its Service 

Agreement. 

23 Sale or Assignment of Transmission 

Service 

23.1 Procedures for Assignment or 

Transfer of Service 

Subject to Commission approval of 

any necessary filings, a Transmission 

Customer may sell, assign, or transfer all 

or a portion of its rights under its 

Service Agreement, but only to another 

Eligible Customer (the Assignee). The 

Transmission Customer that sells, 

assigns or transfers its rights under its 

Service Agreement is hereafter referred 

to as the Reseller. Compensation to 

Resellers shall be at rates established by 

agreement with the Assignee. The 


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12520 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

Assignee must execute a service 

agreement with the Transmission 

Provider prior to the date on which the 

reassigned service commences that will 

govern the provision of reassigned 

service. The Transmission Provider 

shall credit or charge the Reseller, as 

appropriate, for any differences between 

the price reflected in the Assignee’s 

Service Agreement and the Reseller’s 

Service Agreement with the 

Transmission Provider. If the Assignee 

does not request any change in the 

Point(s) of Receipt or the Point(s) of 

Delivery, or a change in any other term 

or condition set forth in the original 

Service Agreement, the Assignee will 

receive the same services as did the 

Reseller and the priority of service for 

the Assignee will be the same as that of 

the Reseller. The Assignee will be 

subject to all terms and conditions of 

this Tariff. If the Assignee requests a 

change in service, the reservation 

priority of service will be determined by 

the Transmission Provider pursuant to 

Section 13.2. 

23.2 Limitations on Assignment or 

Transfer of Service 

If the Assignee requests a change in 

the Point(s) of Receipt or Point(s) of 

Delivery, or a change in any other 

specifications set forth in the original 

Service Agreement, the Transmission 

Provider will consent to such change 

subject to the provisions of the Tariff, 

provided that the change will not impair 

the operation and reliability of the 

Transmission Provider’s generation, 

transmission, or distribution systems. 

The Assignee shall compensate the 

Transmission Provider for performing 

any System Impact Study needed to 

evaluate the capability of the 

Transmission System to accommodate 

the proposed change and any additional 

costs resulting from such change. The 

Reseller shall remain liable for the 

performance of all obligations under the 

Service Agreement, except as 

specifically agreed to by the 

Transmission Provider and the Reseller 

through an amendment to the Service 

Agreement. 

23.3 Information on Assignment or 

Transfer of Service 

In accordance with Section 4, all sales 

or assignments of capacity must be 

conducted through or otherwise posted 

on the Transmission Provider’s OASIS 

on or before the date the reassigned 

service commences and are subject to 

Section 23.1. Resellers may also use the 

Transmission Provider’s OASIS to post 

transmission capacity available for 

resale. 

24 Metering and Power Factor 

Correction at Receipt and Delivery 

Points(s) 

24.1 Transmission Customer 

Obligations 

Unless otherwise agreed, the 

Transmission Customer shall be 

responsible for installing and 

maintaining compatible metering and 

communications equipment to 

accurately account for the capacity and 

energy being transmitted under Part II of 

the Tariff and to communicate the 

information to the Transmission 

Provider. Such equipment shall remain 

the property of the Transmission 

Customer. 

24.2 Transmission Provider Access to 

Metering Data 

The Transmission Provider shall have 

access to metering data, which may 

reasonably be required to facilitate 

measurements and billing under the 

Service Agreement. 

24.3 Power Factor 

Unless otherwise agreed, the 

Transmission Customer is required to 

maintain a power factor within the same 

range as the Transmission Provider 

pursuant to Good Utility Practices. The 

power factor requirements are specified 

in the Service Agreement where 

applicable. 

25 Compensation for Transmission 

Service 

Rates for Firm and Non-Firm PointTo-Point Transmission Service are 

provided in the Schedules appended to 

the Tariff: Firm Point-To-Point 

Transmission Service (Schedule 7); and 

Non-Firm Point-To-Point Transmission 

Service (Schedule 8). The Transmission 

Provider shall use Part II of the Tariff to 

make its Third-Party Sales. The 

Transmission Provider shall account for 

such use at the applicable Tariff rates, 

pursuant to Section 8. 

26 Stranded Cost Recovery 

The Transmission Provider may seek 

to recover stranded costs from the 

Transmission Customer pursuant to this 

Tariff in accordance with the terms, 

conditions and procedures set forth in 

FERC Order No. 888. However, the 

Transmission Provider must separately 

file any specific proposed stranded cost 

charge under Section 205 of the Federal 

Power Act. 

27 Compensation for New Facilities 

and Redispatch Costs 

Whenever a System Impact Study 

performed by the Transmission Provider 

in connection with the provision of 

Firm Point-To-Point Transmission 

Service identifies the need for new 

facilities, the Transmission Customer 

shall be responsible for such costs to the 

extent consistent with Commission 

policy. Whenever a System Impact 

Study performed by the Transmission 

Provider identifies capacity constraints 

that may be relieved by redispatching 

the Transmission Provider’s resources to 

eliminate such constraints, the 

Transmission Customer shall be 

responsible for the redispatch costs to 

the extent consistent with Commission 

policy. 

III. Network Integration Transmission 

Service 

Preamble 

The Transmission Provider will 

provide Network Integration 

Transmission Service pursuant to the 

applicable terms and conditions 

contained in the Tariff and Service 

Agreement. Network Integration 

Transmission Service allows the 

Network Customer to integrate, 

economically dispatch and regulate its 

current and planned Network Resources 

to serve its Network Load in a manner 

comparable to that in which the 

Transmission Provider utilizes its 

Transmission System to serve its Native 

Load Customers. Network Integration 

Transmission Service also may be used 

by the Network Customer to deliver 

economy energy purchases to its 

Network Load from non-designated 

resources on an as-available basis 

without additional charge. Transmission 

service for sales to non-designated loads 

will be provided pursuant to the 

applicable terms and conditions of Part 

II of the Tariff. 

28 Nature of Network Integration 

Transmission Service 

28.1 Scope of Service 

Network Integration Transmission 

Service is a transmission service that 

allows Network Customers to efficiently 

and economically utilize their Network 

Resources (as well as other nondesignated generation resources) to 

serve their Network Load located in the 

Transmission Provider’s Control Area 

and any additional load that may be 

designated pursuant to Section 31.3 of 

the Tariff. The Network Customer taking 

Network Integration Transmission 

Service must obtain or provide 

Ancillary Services pursuant to Section 

3. 

28.2 Transmission Provider 

Responsibilities 

The Transmission Provider will plan, 

construct, operate and maintain its 


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Transmission System in accordance 

with Good Utility Practice and its 

planning obligations in Attachment K in 

order to provide the Network Customer 

with Network Integration Transmission 

Service over the Transmission 

Provider’s Transmission System. The 

Transmission Provider, on behalf of its 

Native Load Customers, shall be 

required to designate resources and 

loads in the same manner as any 

Network Customer under Part III of this 

Tariff. This information must be 

consistent with the information used by 

the Transmission Provider to calculate 

available transfer capability. The 

Transmission Provider shall include the 

Network Customer’s Network Load in 

its Transmission System planning and 

shall, consistent with Good Utility 

Practice and Attachment K, endeavor to 

construct and place into service 

sufficient transfer capability to deliver 

the Network Customer’s Network 

Resources to serve its Network Load on 

a basis comparable to the Transmission 

Provider’s delivery of its own generating 

and purchased resources to its Native 

Load Customers. 

28.3 Network Integration Transmission 

Service 

The Transmission Provider will 

provide firm transmission service over 

its Transmission System to the Network 

Customer for the delivery of capacity 

and energy from its designated Network 

Resources to service its Network Loads 

on a basis that is comparable to the 

Transmission Provider’s use of the 

Transmission System to reliably serve 

its Native Load Customers. 

28.4 Secondary Service 

The Network Customer may use the 

Transmission Provider’s Transmission 

System to deliver energy to its Network 

Loads from resources that have not been 

designated as Network Resources. Such 

energy shall be transmitted, on an asavailable basis, at no additional charge. 

Secondary service shall not require the 

filing of an Application for Network 

Integration Transmission Service under 

the Tariff. However, all other 

requirements of Part III of the Tariff 

(except for transmission rates) shall 

apply to secondary service. Deliveries 

from resources other than Network 

Resources will have a higher priority 

than any Non-Firm Point-To-Point 

Transmission Service under Part II of 

the Tariff. 

28.5 Real Power Losses 

Real Power Losses are associated with 

all transmission service. The 

Transmission Provider is not obligated 

to provide Real Power Losses. The 

Network Customer is responsible for 

replacing losses associated with all 

transmission service as calculated by 

the Transmission Provider. The 

applicable Real Power Loss factors are 

as follows: [To be completed by the 

Transmission Provider]. 

28.6 Restrictions on Use of Service 

The Network Customer shall not use 

Network Integration Transmission 

Service for (i) sales of capacity and 

energy to non-designated loads, or (ii) 

direct or indirect provision of 

transmission service by the Network 

Customer to third parties. All Network 

Customers taking Network Integration 

Transmission Service shall use PointTo-Point Transmission Service under 

Part II of the Tariff for any Third-Party 

Sale which requires use of the 

Transmission Provider’s Transmission 

System. The Transmission Provider 

shall specify any appropriate charges 

and penalties and all related terms and 

conditions applicable in the event that 

a Network Customer uses Network 

Integration Transmission Service or 

secondary service pursuant to Section 

28.4 to facilitate a wholesale sale that 

does not serve a Network Load. 

29 Initiating Service 

29.1 Condition Precedent for 

Receiving Service 

Subject to the terms and conditions of 

Part III of the Tariff, the Transmission 

Provider will provide Network 

Integration Transmission Service to any 

Eligible Customer, provided that (i) the 

Eligible Customer completes an 

Application for service as provided 

under Part III of the Tariff, (ii) the 

Eligible Customer and the Transmission 

Provider complete the technical 

arrangements set forth in Sections 29.3 

and 29.4, (iii) the Eligible Customer 

executes a Service Agreement pursuant 

to Attachment F for service under Part 

III of the Tariff or requests in writing 

that the Transmission Provider file a 

proposed unexecuted Service 

Agreement with the Commission, and 

(iv) the Eligible Customer executes a 

Network Operating Agreement with the 

Transmission Provider pursuant to 

Attachment G, or requests in writing 

that the Transmission Provider file a 

proposed unexecuted Network 

Operating Agreement. 

29.2 Application Procedures 

An Eligible Customer requesting 

service under Part III of the Tariff must 

submit an Application, with a deposit 

approximating the charge for one month 

of service, to the Transmission Provider 

as far as possible in advance of the 

month in which service is to commence. 

Unless subject to the procedures in 

Section 2, Completed Applications for 

Network Integration Transmission 

Service will be assigned a priority 

according to the date and time the 

Application is received, with the 

earliest Application receiving the 

highest priority. Applications should be 

submitted by entering the information 

listed below on the Transmission 

Provider’s OASIS. Prior to 

implementation of the Transmission 

Provider’s OASIS, a Completed 

Application may be submitted by (i) 

transmitting the required information to 

the Transmission Provider by telefax, or 

(ii) providing the information by 

telephone over the Transmission 

Provider’s time recorded telephone line. 

Each of these methods will provide a 

time-stamped record for establishing the 

service priority of the Application. A 

Completed Application shall provide all 

of the information included in 18 CFR 

2.20 including but not limited to the 

following: 

(i) The identity, address, telephone 

number and facsimile number of the 

party requesting service; 

(ii) A statement that the party 

requesting service is, or will be upon 

commencement of service, an Eligible 

Customer under the Tariff; 

(iii) A description of the Network 

Load at each delivery point. This 

description should separately identify 

and provide the Eligible Customer’s best 

estimate of the total loads to be served 

at each transmission voltage level, and 

the loads to be served from each 

Transmission Provider substation at the 

same transmission voltage level. The 

description should include a ten (10) 

year forecast of summer and winter load 

and resource requirements beginning 

with the first year after the service is 

scheduled to commence; 

(iv) The amount and location of any 

interruptible loads included in the 

Network Load. This shall include the 

summer and winter capacity 

requirements for each interruptible load 

(had such load not been interruptible), 

that portion of the load subject to 

interruption, the conditions under 

which an interruption can be 

implemented and any limitations on the 

amount and frequency of interruptions. 

An Eligible Customer should identify 

the amount of interruptible customer 

load (if any) included in the 10 year 

load forecast provided in response to 

(iii) above; 

(v) A description of Network 

Resources (current and 10-year 

projection). For each on-system Network 

Resource, such description shall 

include: 


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• Unit size and amount of capacity 

from that unit to be designated as 

Network Resource 

• VAR capability (both leading and 

lagging) of all generators 

• Operating restrictions 

—Any periods of restricted operations 

throughout the year 

—Maintenance schedules 

—Minimum loading level of unit 

—Normal operating level of unit 

—Any must-run unit designations 

required for system reliability or 

contract reasons 

• Approximate variable generating 

cost ($/MWH) for redispatch 

computations 

• Arrangements governing sale and 

delivery of power to third parties from 

generating facilities located in the 

Transmission Provider Control Area, 

where only a portion of unit output is 

designated as a Network Resource; 

For each off-system Network 

Resource, such description shall 

include: 

• Identification of the Network 

Resource as an off-system resource 

• Amount of power to which the 

customer has rights 

• Identification of the control area(s) 

from which the power will originate 

• Delivery point(s) to the 

Transmission Provider’s Transmission 

System 

• Transmission arrangements on the 

external transmission system(s) 

• Operating restrictions, if any 

—Any periods of restricted operations 

throughout the year 

—Maintenance schedules 

—Minimum loading level of unit 

—Normal operating level of unit 

—Any must-run unit designations 

required for system reliability or 

contract reasons 

• Approximate variable generating 

cost ($/MWH) for redispatch 

computations; 

(vi) Description of Eligible Customer’s 

transmission system: 

• Load flow and stability data, such 

as real and reactive parts of the load, 

lines, transformers, reactive devices and 

load type, including normal and 

emergency ratings of all transmission 

equipment in a load flow format 

compatible with that used by the 

Transmission Provider 

• Operating restrictions needed for 

reliability 

• Operating guides employed by 

system operators 

• Contractual restrictions or 

committed uses of the Eligible 

Customer’s transmission system, other 

than the Eligible Customer’s Network 

Loads and Resources 

• Location of Network Resources 

described in subsection (v) above 

• 10 year projection of system 

expansions or upgrades 

• Transmission System maps that 

include any proposed expansions or 

upgrades 

• Thermal ratings of Eligible 

Customer’s Control Area ties with other 

Control Areas; 

(vii) Service Commencement Date and 

the term of the requested Network 

Integration Transmission Service. The 

minimum term for Network Integration 

Transmission Service is one year; 

(viii) A statement signed by an 

authorized officer from or agent of the 

Network Customer attesting that all of 

the network resources listed pursuant to 

Section 29.2(v) satisfy the following 

conditions: 

(1) The Network Customer owns the 

resource, has committed to purchase 

generation pursuant to an executed 

contract, or has committed to purchase 

generation where execution of a contract 

is contingent upon the availability of 

transmission service under Part III of the 

Tariff; and (2) the Network Resources do 

not include any resources, or any 

portion thereof, that are committed for 

sale to non-designated third party load 

or otherwise cannot be called upon to 

meet the Network Customer’s Network 

Load on a non-interruptible basis; and 

(ix) Any additional information 

required of the Transmission Customer 

as specified in the Transmission 

Provider’s planning process established 

in Attachment K. 

Unless the Parties agree to a different 

time frame, the Transmission Provider 

must acknowledge the request within 

ten (10) days of receipt. The 

acknowledgement must include a date 

by which a response, including a 

Service Agreement, will be sent to the 

Eligible Customer. If an Application 

fails to meet the requirements of this 

section, the Transmission Provider shall 

notify the Eligible Customer requesting 

service within fifteen (15) days of 

receipt and specify the reasons for such 

failure. Wherever possible, the 

Transmission Provider will attempt to 

remedy deficiencies in the Application 

through informal communications with 

the Eligible Customer. If such efforts are 

unsuccessful, the Transmission Provider 

shall return the Application without 

prejudice to the Eligible Customer filing 

a new or revised Application that fully 

complies with the requirements of this 

section. The Eligible Customer will be 

assigned a new priority consistent with 

the date of the new or revised 

Application. The Transmission Provider 

shall treat this information consistent 

with the standards of conduct contained 

in Part 37 of the Commission’s 

regulations. 

29.3 Technical Arrangements to be 

Completed Prior to Commencement of 

Service 

Network Integration Transmission 

Service shall not commence until the 

Transmission Provider and the Network 

Customer, or a third party, have 

completed installation of all equipment 

specified under the Network Operating 

Agreement consistent with Good Utility 

Practice and any additional 

requirements reasonably and 

consistently imposed to ensure the 

reliable operation of the Transmission 

System. The Transmission Provider 

shall exercise reasonable efforts, in 

coordination with the Network 

Customer, to complete such 

arrangements as soon as practicable 

taking into consideration the Service 

Commencement Date. 

29.4 Network Customer Facilities 

The provision of Network Integration 

Transmission Service shall be 

conditioned upon the Network 

Customer’s constructing, maintaining 

and operating the facilities on its side of 

each delivery point or interconnection 

necessary to reliably deliver capacity 

and energy from the Transmission 

Provider’s Transmission System to the 

Network Customer. The Network 

Customer shall be solely responsible for 

constructing or installing all facilities on 

the Network Customer’s side of each 

such delivery point or interconnection. 

29.5 Filing of Service Agreement 

The Transmission Provider will file 

Service Agreements with the 

Commission in compliance with 

applicable Commission regulations. 

30 Network Resources 

30.1 Designation of Network Resources 

Network Resources shall include all 

generation owned, purchased or leased 

by the Network Customer designated to 

serve Network Load under the Tariff. 

Network Resources may not include 

resources, or any portion thereof, that 

are committed for sale to nondesignated third party load or otherwise 

cannot be called upon to meet the 

Network Customer’s Network Load on a 

non-interruptible basis. Any owned or 

purchased resources that were serving 

the Network Customer’s loads under 

firm agreements entered into on or 

before the Service Commencement Date 

shall initially be designated as Network 

Resources until the Network Customer 

terminates the designation of such 

resources. 


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30.2 Designation of New Network 

Resources 

The Network Customer may designate 

a new Network Resource by providing 

the Transmission Provider with as much 

advance notice as practicable. A 

designation of a new Network Resource 

must be made through the Transmission 

Provider’s OASIS by a request for 

modification of service pursuant to an 

Application under Section 29. This 

request must include a statement that 

the new network resource satisfies the 

following conditions: (1) the Network 

Customer owns the resource, has 

committed to purchase generation 

pursuant to an executed contract, or has 

committed to purchase generation 

where execution of a contract is 

contingent upon the availability of 

transmission service under Part III of the 

Tariff; and (2) The Network Resources 

do not include any resources, or any 

portion thereof, that are committed for 

sale to non-designated third party load 

or otherwise cannot be called upon to 

meet the Network Customer’s Network 

Load on a non-interruptible basis. The 

Network Customer’s request will be 

deemed deficient if it does not include 

this statement and the Transmission 

Provider will follow the procedures for 

a deficient application as described in 

Section 29.2 of the Tariff. 

30.3 Termination of Network 

Resources 

The Network Customer may terminate 

the designation of all or part of a 

generating resource as a Network 

Resource by providing notification to 

the Transmission Provider through 

OASIS as soon as reasonably 

practicable, but not later than the firm 

scheduling deadline for the period of 

termination. Any request for 

termination of Network Resource status 

must be submitted on OASIS, and 

should indicate whether the request is 

for indefinite or temporary termination. 

A request for indefinite termination of 

Network Resource status must indicate 

the date and time that the termination 

is to be effective, and the identification 

and capacity of the resource(s) or 

portions thereof to be indefinitely 

terminated. A request for temporary 

termination of Network Resource status 

must include the following: 

(i) Effective date and time of 

temporary termination; 

(ii) Effective date and time of 

redesignation, following period of 

temporary termination; 

(iii) Identification and capacity of 

resource(s) or portions thereof to be 

temporarily terminated; 

(iv) Resource description and 

attestation for redesignating the network 

resource following the temporary 

termination, in accordance with Section 

30.2; and 

(v) Identification of any related 

transmission service requests to be 

evaluated concomitantly with the 

request for temporary termination, such 

that the requests for undesignation and 

the request for these related 

transmission service requests must be 

approved or denied as a single request. 

The evaluation of these related 

transmission service requests must take 

into account the termination of the 

network resources identified in (iii) 

above, as well as all competing 

transmission service requests of higher 

priority. 

As part of a temporary termination, a 

Network Customer may only redesignate 

the same resource that was originally 

designated, or a portion thereof. 

Requests to redesignate a different 

resource and/or a resource with 

increased capacity will be deemed 

deficient and the Transmission Provider 

will follow the procedures for a 

deficient application as described in 

Section 29.2 of the Tariff. 

30.4 Operation of Network Resources 

The Network Customer shall not 

operate its designated Network 

Resources located in the Network 

Customer’s or Transmission Provider’s 

Control Area such that the output of 

those facilities exceeds its designated 

Network Load, plus Non-Firm Sales 

delivered pursuant to Part II of the 

Tariff, plus losses. This limitation shall 

not apply to changes in the operation of 

a Transmission Customer’s Network 

Resources at the request of the 

Transmission Provider to respond to an 

emergency or other unforeseen 

condition which may impair or degrade 

the reliability of the Transmission 

System. For all Network Resources not 

physically connected with the 

Transmission Provider’s Transmission 

System, the Network Customer may not 

schedule delivery of energy in excess of 

the Network Resource’s capacity, as 

specified in the Network Customer’s 

Application pursuant to Section 29, 

unless the Network Customer supports 

such delivery within the Transmission 

Provider’s Transmission System by 

either obtaining Point-to-Point 

Transmission Service or utilizing 

secondary service pursuant to Section 

28.4. The Transmission Provider shall 

specify the rate treatment and all related 

terms and conditions applicable in the 

event that a Network Customer’s 

schedule at the delivery point for a 

Network Resource not physically 

interconnected with the Transmission 

Provider’s Transmission System exceeds 

the Network Resource’s designated 

capacity, excluding energy delivered 

using secondary service or Point-toPoint Transmission Service. 

30.5 Network Customer Redispatch 

Obligation 

As a condition to receiving Network 

Integration Transmission Service, the 

Network Customer agrees to redispatch 

its Network Resources as requested by 

the Transmission Provider pursuant to 

Section 33.2. To the extent practical, the 

redispatch of resources pursuant to this 

section shall be on a least cost, nondiscriminatory basis between all 

Network Customers, and the 

Transmission Provider. 

30.6 Transmission Arrangements for 

Network Resources Not Physically 

Interconnected With The Transmission 

Provider 

The Network Customer shall be 

responsible for any arrangements 

necessary to deliver capacity and energy 

from a Network Resource not physically 

interconnected with the Transmission 

Provider’s Transmission System. The 

Transmission Provider will undertake 

reasonable efforts to assist the Network 

Customer in obtaining such 

arrangements, including without 

limitation, providing any information or 

data required by such other entity 

pursuant to Good Utility Practice. 

30.7 Limitation on Designation of 

Network Resources 

The Network Customer must 

demonstrate that it owns or has 

committed to purchase generation 

pursuant to an executed contract in 

order to designate a generating resource 

as a Network Resource. Alternatively, 

the Network Customer may establish 

that execution of a contract is 

contingent upon the availability of 

transmission service under Part III of the 

Tariff. 

30.8 Use of Interface Capacity by the 

Network Customer 

There is no limitation upon a Network 

Customer’s use of the Transmission 

Provider’s Transmission System at any 

particular interface to integrate the 

Network Customer’s Network Resources 

(or substitute economy purchases) with 

its Network Loads. However, a Network 

Customer’s use of the Transmission 

Provider’s total interface capacity with 

other transmission systems may not 

exceed the Network Customer’s Load. 

30.9 Network Customer Owned 

Transmission Facilities 

The Network Customer that owns 

existing transmission facilities that are 


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integrated with the Transmission 

Provider’s Transmission System may be 

eligible to receive consideration either 

through a billing credit or some other 

mechanism. In order to receive such 

consideration the Network Customer 

must demonstrate that its transmission 

facilities are integrated into the plans or 

operations of the Transmission 

Provider, to serve its power and 

transmission customers. For facilities 

added by the Network Customer 

subsequent to the [the effective date of 

a Final Rule in RM05–25–000], the 

Network Customer shall receive credit 

for such transmission facilities added if 

such facilities are integrated into the 

operations of the Transmission 

Provider’s facilities; provided however, 

the Network Customer’s transmission 

facilities shall be presumed to be 

integrated if such transmission facilities, 

if owned by the Transmission Provider, 

would be eligible for inclusion in the 

Transmission Provider’s annual 

transmission revenue requirement as 

specified in Attachment H. Calculation 

of any credit under this subsection shall 

be addressed in either the Network 

Customer’s Service Agreement or any 

other agreement between the Parties. 

31 Designation of Network Load 

31.1 Network Load 

The Network Customer must 

designate the individual Network Loads 

on whose behalf the Transmission 

Provider will provide Network 

Integration Transmission Service. The 

Network Loads shall be specified in the 

Service Agreement. 

31.2 New Network Loads Connected 

With the Transmission Provider 

The Network Customer shall provide 

the Transmission Provider with as much 

advance notice as reasonably practicable 

of the designation of new Network Load 

that will be added to its Transmission 

System. A designation of new Network 

Load must be made through a 

modification of service pursuant to a 

new Application. The Transmission 

Provider will use due diligence to 

install any transmission facilities 

required to interconnect a new Network 

Load designated by the Network 

Customer. The costs of new facilities 

required to interconnect a new Network 

Load shall be determined in accordance 

with the procedures provided in Section 

32.4 and shall be charged to the 

Network Customer in accordance with 

Commission policies. 

31.3 Network Load Not Physically 

Interconnected With the Transmission 

Provider 

This section applies to both initial 

designation pursuant to Section 31.1 

and the subsequent addition of new 

Network Load not physically 

interconnected with the Transmission 

Provider. To the extent that the Network 

Customer desires to obtain transmission 

service for a load outside the 

Transmission Provider’s Transmission 

System, the Network Customer shall 

have the option of (1) electing to include 

the entire load as Network Load for all 

purposes under Part III of the Tariff and 

designating Network Resources in 

connection with such additional 

Network Load, or (2) excluding that 

entire load from its Network Load and 

purchasing Point-To-Point Transmission 

Service under Part II of the Tariff. To the 

extent that the Network Customer gives 

notice of its intent to add a new 

Network Load as part of its Network 

Load pursuant to this section the 

request must be made through a 

modification of service pursuant to a 

new Application. 

31.4 New Interconnection Points 

To the extent the Network Customer 

desires to add a new Delivery Point or 

interconnection point between the 

Transmission Provider’s Transmission 

System and a Network Load, the 

Network Customer shall provide the 

Transmission Provider with as much 

advance notice as reasonably 

practicable. 

31.5 Changes in Service Requests 

Under no circumstances shall the 

Network Customer’s decision to cancel 

or delay a requested change in Network 

Integration Transmission Service (e.g. 

the addition of a new Network Resource 

or designation of a new Network Load) 

in any way relieve the Network 

Customer of its obligation to pay the 

costs of transmission facilities 

constructed by the Transmission 

Provider and charged to the Network 

Customer as reflected in the Service 

Agreement. However, the Transmission 

Provider must treat any requested 

change in Network Integration 

Transmission Service in a nondiscriminatory manner. 

31.6 Annual Load and Resource 

Information Updates 

The Network Customer shall provide 

the Transmission Provider with annual 

updates of Network Load and Network 

Resource forecasts consistent with those 

included in its Application for Network 

Integration Transmission Service under 

Part III of the Tariff including, but not 

limited to, any information provided 

under section 29.2(ix) pursuant to the 

Transmission Provider’s planning 

process in Attachment K. The Network 

Customer also shall provide the 

Transmission Provider with timely 

written notice of material changes in 

any other information provided in its 

Application relating to the Network 

Customer’s Network Load, Network 

Resources, its transmission system or 

other aspects of its facilities or 

operations affecting the Transmission 

Provider’s ability to provide reliable 

service. 

32 Additional Study Procedures for 

Network Integration Transmission 

Service Requests 

32.1 Notice of Need for System Impact 

Study 

After receiving a request for service, 

the Transmission Provider shall 

determine on a non-discriminatory basis 

whether a System Impact Study is 

needed. A description of the 

Transmission Provider’s methodology 

for completing a System Impact Study is 

provided in Attachment D. If the 

Transmission Provider determines that a 

System Impact Study is necessary to 

accommodate the requested service, it 

shall so inform the Eligible Customer, as 

soon as practicable. In such cases, the 

Transmission Provider shall within 

thirty (30) days of receipt of a 

Completed Application, tender a System 

Impact Study Agreement pursuant to 

which the Eligible Customer shall agree 

to reimburse the Transmission Provider 

for performing the required System 

Impact Study. For a service request to 

remain a Completed Application, the 

Eligible Customer shall execute the 

System Impact Study Agreement and 

return it to the Transmission Provider 

within fifteen (15) days. If the Eligible 

Customer elects not to execute the 

System Impact Study Agreement, its 

Application shall be deemed withdrawn 

and its deposit shall be returned with 

interest. 

32.2 System Impact Study Agreement 

and Cost Reimbursement 

(i) The System Impact Study 

Agreement will clearly specify the 

Transmission Provider’s estimate of the 

actual cost, and time for completion of 

the System Impact Study. The charge 

shall not exceed the actual cost of the 

study. In performing the System Impact 

Study, the Transmission Provider shall 

rely, to the extent reasonably 

practicable, on existing transmission 

planning studies. The Eligible Customer 

will not be assessed a charge for such 

existing studies; however, the Eligible 


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Customer will be responsible for charges 

associated with any modifications to 

existing planning studies that are 

reasonably necessary to evaluate the 

impact of the Eligible Customer’s 

request for service on the Transmission 

System. 

(ii) If in response to multiple Eligible 

Customers requesting service in relation 

to the same competitive solicitation, a 

single System Impact Study is sufficient 

for the Transmission Provider to 

accommodate the service requests, the 

costs of that study shall be pro-rated 

among the Eligible Customers. 

(iii) For System Impact Studies that 

the Transmission Provider conducts on 

its own behalf, the Transmission 

Provider shall record the cost of the 

System Impact Studies pursuant to 

Section 8. 

32.3 System Impact Study Procedures 

Upon receipt of an executed System 

Impact Study Agreement, the 

Transmission Provider will use due 

diligence to complete the required 

System Impact Study within a sixty (60) 

day period. The System Impact Study 

shall identify any system constraints 

and redispatch options, additional 

Direct Assignment Facilities or Network 

Upgrades required to provide the 

requested service. In the event that the 

Transmission Provider is unable to 

complete the required System Impact 

Study within such time period, it shall 

so notify the Eligible Customer and 

provide an estimated completion date 

along with an explanation of the reasons 

why additional time is required to 

complete the required studies. A copy of 

the completed System Impact Study and 

related work papers shall be made 

available to the Eligible Customer as 

soon as the System Impact Study is 

complete. The Transmission Provider 

will use the same due diligence in 

completing the System Impact Study for 

an Eligible Customer as it uses when 

completing studies for itself. The 

Transmission Provider shall notify the 

Eligible Customer immediately upon 

completion of the System Impact Study 

if the Transmission System will be 

adequate to accommodate all or part of 

a request for service or that no costs are 

likely to be incurred for new 

transmission facilities or upgrades. In 

order for a request to remain a 

Completed Application, within fifteen 

(15) days of completion of the System 

Impact Study the Eligible Customer 

must execute a Service Agreement or 

request the filing of an unexecuted 

Service Agreement, or the Application 

shall be deemed terminated and 

withdrawn. 

32.4 Facilities Study Procedures 

If a System Impact Study indicates 

that additions or upgrades to the 

Transmission System are needed to 

supply the Eligible Customer’s service 

request, the Transmission Provider, 

within thirty (30) days of the 

completion of the System Impact Study, 

shall tender to the Eligible Customer a 

Facilities Study Agreement pursuant to 

which the Eligible Customer shall agree 

to reimburse the Transmission Provider 

for performing the required Facilities 

Study. For a service request to remain 

a Completed Application, the Eligible 

Customer shall execute the Facilities 

Study Agreement and return it to the 

Transmission Provider within fifteen 

(15) days. If the Eligible Customer elects 

not to execute the Facilities Study 

Agreement, its Application shall be 

deemed withdrawn and its deposit shall 

be returned with interest. Upon receipt 

of an executed Facilities Study 

Agreement, the Transmission Provider 

will use due diligence to complete the 

required Facilities Study within a sixty 

(60) day period. If the Transmission 

Provider is unable to complete the 

Facilities Study in the allotted time 

period, the Transmission Provider shall 

notify the Eligible Customer and 

provide an estimate of the time needed 

to reach a final determination along 

with an explanation of the reasons that 

additional time is required to complete 

the study. When completed, the 

Facilities Study will include a good 

faith estimate of (i) the cost of Direct 

Assignment Facilities to be charged to 

the Eligible Customer, (ii) the Eligible 

Customer’s appropriate share of the cost 

of any required Network Upgrades, and 

(iii) the time required to complete such 

construction and initiate the requested 

service. The Eligible Customer shall 

provide the Transmission Provider with 

a letter of credit or other reasonable 

form of security acceptable to the 

Transmission Provider equivalent to the 

costs of new facilities or upgrades 

consistent with commercial practices as 

established by the Uniform Commercial 

Code. The Eligible Customer shall have 

thirty (30) days to execute a Service 

Agreement or request the filing of an 

unexecuted Service Agreement and 

provide the required letter of credit or 

other form of security or the request no 

longer will be a Completed Application 

and shall be deemed terminated and 

withdrawn. 

32.5 Penalties for Failure To Meet 

Study Deadlines 

Section 19.9 defines penalties that 

apply for failure to meet the 60-day 

study completion due diligence 

deadlines for System Impact Studies 

and Facilities Studies under Part II of 

the Tariff. These same requirements and 

penalties apply to service under Part III 

of the Tariff. 

33 Load Shedding and Curtailments 

33.1 Procedures 

Prior to the Service Commencement 

Date, the Transmission Provider and the 

Network Customer shall establish Load 

Shedding and Curtailment procedures 

pursuant to the Network Operating 

Agreement with the objective of 

responding to contingencies on the 

Transmission System and on systems 

directly and indirectly interconnected 

with Transmission Provider’s 

Transmission System. The Parties will 

implement such programs during any 

period when the Transmission Provider 

determines that a system contingency 

exists and such procedures are 

necessary to alleviate such contingency. 

The Transmission Provider will notify 

all affected Network Customers in a 

timely manner of any scheduled 

Curtailment. 

33.2 Transmission Constraints 

During any period when the 

Transmission Provider determines that a 

transmission constraint exists on the 

Transmission System, and such 

constraint may impair the reliability of 

the Transmission Provider’s system, the 

Transmission Provider will take 

whatever actions, consistent with Good 

Utility Practice, that are reasonably 

necessary to maintain the reliability of 

the Transmission Provider’s system. To 

the extent the Transmission Provider 

determines that the reliability of the 

Transmission System can be maintained 

by redispatching resources, the 

Transmission Provider will initiate 

procedures pursuant to the Network 

Operating Agreement to redispatch all 

Network Resources and the 

Transmission Provider’s own resources 

on a least-cost basis without regard to 

the ownership of such resources. Any 

redispatch under this section may not 

unduly discriminate between the 

Transmission Provider’s use of the 

Transmission System on behalf of its 

Native Load Customers and any 

Network Customer’s use of the 

Transmission System to serve its 

designated Network Load. 

33.3 Cost Responsibility for Relieving 

Transmission Constraints 

Whenever the Transmission Provider 

implements least-cost redispatch 

procedures in response to a 

transmission constraint, the 

Transmission Provider and Network 


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Customers will each bear a 

proportionate share of the total 

redispatch cost based on their respective 

Load Ratio Shares. 

33.4 Curtailments of Scheduled 

Deliveries 

If a transmission constraint on the 

Transmission Provider’s Transmission 

System cannot be relieved through the 

implementation of least-cost redispatch 

procedures and the Transmission 

Provider determines that it is necessary 

to Curtail scheduled deliveries, the 

Parties shall Curtail such schedules in 

accordance with the Network Operating 

Agreement or pursuant to the 

Transmission Loading Relief procedures 

specified in Attachment J. 

33.5 Allocation of Curtailments 

The Transmission Provider shall, on a 

non-discriminatory basis, Curtail the 

transaction(s) that effectively relieve the 

constraint. However, to the extent 

practicable and consistent with Good 

Utility Practice, any Curtailment will be 

shared by the Transmission Provider 

and Network Customer in proportion to 

their respective Load Ratio Shares. The 

Transmission Provider shall not direct 

the Network Customer to Curtail 

schedules to an extent greater than the 

Transmission Provider would Curtail 

the Transmission Provider’s schedules 

under similar circumstances. 

33.6 Load Shedding 

To the extent that a system 

contingency exists on the Transmission 

Provider’s Transmission System and the 

Transmission Provider determines that 

it is necessary for the Transmission 

Provider and the Network Customer to 

shed load, the Parties shall shed load in 

accordance with previously established 

procedures under the Network 

Operating Agreement. 

33.7 System Reliability 

Notwithstanding any other provisions 

of this Tariff, the Transmission Provider 

reserves the right, consistent with Good 

Utility Practice and on a not unduly 

discriminatory basis, to Curtail Network 

Integration Transmission Service 

without liability on the Transmission 

Provider’s part for the purpose of 

making necessary adjustments to, 

changes in, or repairs on its lines, 

substations and facilities, and in cases 

where the continuance of Network 

Integration Transmission Service would 

endanger persons or property. In the 

event of any adverse condition(s) or 

disturbance(s) on the Transmission 

Provider’s Transmission System or on 

any other system(s) directly or 

indirectly interconnected with the 

Transmission Provider’s Transmission 

System, the Transmission Provider, 

consistent with Good Utility Practice, 

also may Curtail Network Integration 

Transmission Service in order to (i) 

limit the extent or damage of the 

adverse condition(s) or disturbance(s), 

(ii) prevent damage to generating or 

transmission facilities, or (iii) expedite 

restoration of service. The Transmission 

Provider will give the Network 

Customer as much advance notice as is 

practicable in the event of such 

Curtailment. Any Curtailment of 

Network Integration Transmission 

Service will be not unduly 

discriminatory relative to the 

Transmission Provider’s use of the 

Transmission System on behalf of its 

Native Load Customers. The 

Transmission Provider shall specify the 

rate treatment and all related terms and 

conditions applicable in the event that 

the Network Customer fails to respond 

to established Load Shedding and 

Curtailment procedures. 

34 Rates and Charges 

The Network Customer shall pay the 

Transmission Provider for any Direct 

Assignment Facilities, Ancillary 

Services, and applicable study costs, 

consistent with Commission policy, 

along with the following: 

34.1 Monthly Demand Charge 

The Network Customer shall pay a 

monthly Demand Charge, which shall 

be determined by multiplying its Load 

Ratio Share times one twelfth (1⁄12) of 

the Transmission Provider’s Annual 

Transmission Revenue Requirement 

specified in Schedule H. 

34.2 Determination of Network 

Customer’s Monthly Network Load 

The Network Customer’s monthly 

Network Load is its hourly load 

(including its designated Network Load 

not physically interconnected with the 

Transmission Provider under Section 

31.3) coincident with the Transmission 

Provider’s Monthly Transmission 

System Peak. 

34.3 Determination of Transmission 

Provider’s Monthly Transmission 

System Load 

The Transmission Provider’s monthly 

Transmission System load is the 

Transmission Provider’s Monthly 

Transmission System Peak minus the 

coincident peak usage of all Firm PointTo-Point Transmission Service 

customers pursuant to Part II of this 

Tariff plus the Reserved Capacity of all 

Firm Point-To-Point Transmission 

Service customers. 

34.4 Redispatch Charge 

The Network Customer shall pay a 

Load Ratio Share of any redispatch costs 

allocated between the Network 

Customer and the Transmission 

Provider pursuant to Section 33. To the 

extent that the Transmission Provider 

incurs an obligation to the Network 

Customer for redispatch costs in 

accordance with Section 33, such 

amounts shall be credited against the 

Network Customer’s bill for the 

applicable month. 

34.5 Stranded Cost Recovery 

The Transmission Provider may seek 

to recover stranded costs from the 

Network Customer pursuant to this 

Tariff in accordance with the terms, 

conditions and procedures set forth in 

FERC Order No. 888. However, the 

Transmission Provider must separately 

file any proposal to recover stranded 

costs under Section 205 of the Federal 

Power Act. 

35 Operating Arrangements 

35.1 Operation Under the Network 

Operating Agreement 

The Network Customer shall plan, 

construct, operate and maintain its 

facilities in accordance with Good 

Utility Practice and in conformance 

with the Network Operating Agreement. 

35.2 Network Operating Agreement 

The terms and conditions under 

which the Network Customer shall 

operate its facilities and the technical 

and operational matters associated with 

the implementation of Part III of the 

Tariff shall be specified in the Network 

Operating Agreement. The Network 

Operating Agreement shall provide for 

the Parties to (i) operate and maintain 

equipment necessary for integrating the 

Network Customer within the 

Transmission Provider’s Transmission 

System (including, but not limited to, 

remote terminal units, metering, 

communications equipment and 

relaying equipment), (ii) transfer data 

between the Transmission Provider and 

the Network Customer (including, but 

not limited to, heat rates and 

operational characteristics of Network 

Resources, generation schedules for 

units outside the Transmission 

Provider’s Transmission System, 

interchange schedules, unit outputs for 

redispatch required under Section 33, 

voltage schedules, loss factors and other 

real time data), (iii) use software 

programs required for data links and 

constraint dispatching, (iv) exchange 

data on forecasted loads and resources 

necessary for long-term planning, and 

(v) address any other technical and 


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operational considerations required for 

implementation of Part III of the Tariff, 

including scheduling protocols. The 

Network Operating Agreement will 

recognize that the Network Customer 

shall either (i) operate as a Control Area 

under applicable guidelines of the 

Electric Reliability Organization (ERO) 

as defined in 18 CFR 39.1, (ii) satisfy its 

Control Area requirements, including all 

necessary Ancillary Services, by 

contracting with the Transmission 

Provider, or (iii) satisfy its Control Area 

requirements, including all necessary 

Ancillary Services, by contracting with 

another entity, consistent with Good 

Utility Practice, which satisfies the 

applicable reliability guidelines of the 

ERO. The Transmission Provider shall 

not unreasonably refuse to accept 

contractual arrangements with another 

entity for Ancillary Services. The 

Network Operating Agreement is 

included in Attachment G. 

35.3 Network Operating Committee 

A Network Operating Committee 

(Committee) shall be established to 

coordinate operating criteria for the 

Parties’ respective responsibilities under 

the Network Operating Agreement. Each 

Network Customer shall be entitled to 

have at least one representative on the 

Committee. The Committee shall meet 

from time to time as need requires, but 

no less than once each calendar year. 

Schedule 1—Scheduling, System 

Control and Dispatch Service 

This service is required to schedule 

the movement of power through, out of, 

within, or into a Control Area. This 

service can be provided only by the 

operator of the Control Area in which 

the transmission facilities used for 

transmission service are located. 

Scheduling, System Control and 

Dispatch Service is to be provided 

directly by the Transmission Provider (if 

the Transmission Provider is the Control 

Area operator) or indirectly by the 

Transmission Provider making 

arrangements with the Control Area 

operator that performs this service for 

the Transmission Provider’s 

Transmission System. The Transmission 

Customer must purchase this service 

from the Transmission Provider or the 

Control Area operator. The charges for 

Scheduling, System Control and 

Dispatch Service are to be based on the 

rates set forth below. To the extent the 

Control Area operator performs this 

service for the Transmission Provider, 

charges to the Transmission Customer 

are to reflect only a pass-through of the 

costs charged to the Transmission 

Provider by that Control Area operator. 

Schedule 2—Reactive Supply and 

Voltage Control From Generation or 

Other Sources Service 

In order to maintain transmission 

voltages on the Transmission Provider’s 

transmission facilities within acceptable 

limits, generation facilities and nongeneration resources capable of 

providing this service that are under the 

control of the control area operator are 

operated to produce (or absorb) reactive 

power. Thus, Reactive Supply and 

Voltage Control from Generation or 

Other Sources Service must be provided 

for each transaction on the 

Transmission Provider’s transmission 

facilities. The amount of Reactive 

Supply and Voltage Control from 

Generation or Other Sources Service 

that must be supplied with respect to 

the Transmission Customer’s 

transaction will be determined based on 

the reactive power support necessary to 

maintain transmission voltages within 

limits that are generally accepted in the 

region and consistently adhered to by 

the Transmission Provider. 

Reactive Supply and Voltage Control 

from Generation or Other Sources 

Service is to be provided directly by the 

Transmission Provider (if the 

Transmission Provider is the Control 

Area operator) or indirectly by the 

Transmission Provider making 

arrangements with the Control Area 

operator that performs this service for 

the Transmission Provider’s 

Transmission System. The Transmission 

Customer must purchase this service 

from the Transmission Provider or the 

Control Area operator. The charges for 

such service will be based on the rates 

set forth below. To the extent the 

Control Area operator performs this 

service for the Transmission Provider, 

charges to the Transmission Customer 

are to reflect only a pass-through of the 

costs charged to the Transmission 

Provider by the Control Area operator. 

Schedule 3—Regulation and Frequency 

Response Service 

Regulation and Frequency Response 

Service is necessary to provide for the 

continuous balancing of resources 

(generation and interchange) with load 

and for maintaining scheduled 

Interconnection frequency at sixty 

cycles per second (60 Hz). Regulation 

and Frequency Response Service is 

accomplished by committing on-line 

generation whose output is raised or 

lowered (predominantly through the use 

of automatic generating control 

equipment) and by other non-generation 

resources capable of providing this 

service as necessary to follow the 

moment-by-moment changes in load. 

The obligation to maintain this balance 

between resources and load lies with 

the Transmission Provider (or the 

Control Area operator that performs this 

function for the Transmission Provider). 

The Transmission Provider must offer 

this service when the transmission 

service is used to serve load within its 

Control Area. The Transmission 

Customer must either purchase this 

service from the Transmission Provider 

or make alternative comparable 

arrangements to satisfy its Regulation 

and Frequency Response Service 

obligation. The amount of and charges 

for Regulation and Frequency Response 

Service are set forth below. To the 

extent the Control Area operator 

performs this service for the 

Transmission Provider, charges to the 

Transmission Customer are to reflect 

only a pass-through of the costs charged 

to the Transmission Provider by that 

Control Area operator. 

Schedule 4—Energy Imbalance Service 

Energy Imbalance Service is provided 

when a difference occurs between the 

scheduled and the actual delivery of 

energy to a load located within a 

Control Area over a single hour. The 

Transmission Provider must offer this 

service when the transmission service is 

used to serve load within its Control 

Area. The Transmission Customer must 

either purchase this service from the 

Transmission Provider or make 

alternative comparable arrangements, 

which may include use of nongeneration resources capable of 

providing this service, to satisfy its 

Energy Imbalance Service obligation. To 

the extent the Control Area operator 

performs this service for the 

Transmission Provider, charges to the 

Transmission Customer are to reflect 

only a pass-through of the costs charged 

to the Transmission Provider by that 

Control Area operator. The 

Transmission Provider may charge a 

Transmission Customer a penalty for 

either hourly generator imbalances 

under Schedule 9 or hourly energy 

imbalances under this Schedule for the 

same imbalance, but not both. 

The Transmission Provider shall 

establish charges for energy imbalance 

based on the deviation bands as follows: 

(i) Deviations within +/¥1.5 percent 

(with a minimum of 2 MW) of the 

scheduled transaction to be applied 

hourly to any energy imbalance that 

occurs as a result of the Transmission 

Customer’s scheduled transaction(s) 

will be netted on a monthly basis and 

settled financially, at the end of the 

month, at 100 percent of incremental or 

decremental cost; (ii) deviations greater 

than +/¥1.5 percent up to 7.5 percent 


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(or greater than 2 MW up to 10 MW) of 

the scheduled transaction to be applied 

hourly to any energy imbalance that 

occurs as a result of the Transmission 

Customer’s scheduled transaction(s) 

will be settled financially, at the end of 

each month, at 110 percent of 

incremental cost or 90 percent of 

decremental cost, and (iii) deviations 

greater than +/¥7.5 percent (or 10 MW) 

of the scheduled transaction to be 

applied hourly to any energy imbalance 

that occurs as a result of the 

Transmission Customer’s scheduled 

transaction(s) will be settled financially, 

at the end of each month, at 125 percent 

of incremental cost or 75 percent of 

decremental cost. 

For purposes of this Schedule, incremental 

cost and decremental cost represent the 

Transmission Provider’s actual average 

hourly cost of the last 10 MW dispatched to 

supply the Transmission Provider’s Native 

Load Customers, based on the replacement 

cost of fuel, unit heat rates, start-up costs 

(including any commitment and redispatch 

costs), incremental operation and 

maintenance costs, and purchased and 

interchange power costs and taxes, as 

applicable. 

Schedule 5—Operating Reserve—

Spinning Reserve Service 

Spinning Reserve Service is needed to 

serve load immediately in the event of 

a system contingency. Spinning Reserve 

Service may be provided by generating 

units that are on-line and loaded at less 

than maximum output and by nongeneration resources capable of 

providing this service. The 

Transmission Provider must offer this 

service when the transmission service is 

used to serve load within its Control 

Area. The Transmission Customer must 

either purchase this service from the 

Transmission Provider or make 

alternative comparable arrangements to 

satisfy its Spinning Reserve Service 

obligation. The amount of and charges 

for Spinning Reserve Service are set 

forth below. To the extent the Control 

Area operator performs this service for 

the Transmission Provider, charges to 

the Transmission Customer are to reflect 

only a pass-through of the costs charged 

to the Transmission Provider by that 

Control Area operator. 

Schedule 6—Operating Reserve—

Supplemental Reserve Service 

Supplemental Reserve Service is 

needed to serve load in the event of a 

system contingency; however, it is not 

available immediately to serve load but 

rather within a short period of time. 

Supplemental Reserve Service may be 

provided by generating units that are 

on-line but unloaded, by quick-start 

generation or by interruptible load or 

other non-generation resources capable 

of providing this service. The 

Transmission Provider must offer this 

service when the transmission service is 

used to serve load within its Control 

Area. The Transmission Customer must 

either purchase this service from the 

Transmission Provider or make 

alternative comparable arrangements to 

satisfy its Supplemental Reserve Service 

obligation. The amount of and charges 

for Supplemental Reserve Service are 

set forth below. To the extent the 

Control Area operator performs this 

service for the Transmission Provider, 

charges to the Transmission Customer 

are to reflect only a pass-through of the 

costs charged to the Transmission 

Provider by that Control Area operator. 

Schedule 7—Long-Term Firm and 

Short-Term Firm Point-To-Point 

Transmission Service 

The Transmission Customer shall 

compensate the Transmission Provider 

each month for Reserved Capacity at the 

sum of the applicable charges set forth 

below: 

(1) Yearly delivery: one-twelfth of the 

demand charge of $ll/KW of 

Reserved Capacity per year. 

(2) Monthly delivery: $ll/KW of 

Reserved Capacity per month. 

(3) Weekly delivery: $ll/KW of 

Reserved Capacity per week. 

(4) Daily delivery: $ll/KW of 

Reserved Capacity per day. 

The total demand charge in any week, 

pursuant to a reservation for Daily 

delivery, shall not exceed the rate 

specified in section (3) above times the 

highest amount in kilowatts of Reserved 

Capacity in any day during such week. 

(5) Discounts: Three principal 

requirements apply to discounts for 

transmission service as follows (1) any 

offer of a discount made by the 

Transmission Provider must be 

announced to all Eligible Customers 

solely by posting on the OASIS, (2) any 

customer-initiated requests for 

discounts (including requests for use by 

one’s wholesale merchant or an 

affiliate’s use) must occur solely by 

posting on the OASIS, and (3) once a 

discount is negotiated, details must be 

immediately posted on the OASIS. For 

any discount agreed upon for service on 

a path, from point(s) of receipt to 

point(s) of delivery, the Transmission 

Provider must offer the same discounted 

transmission service rate for the same 

time period to all Eligible Customers on 

all unconstrained transmission paths 

that go to the same point(s) of delivery 

on the Transmission System. 

Schedule 8—Non-Firm Point-To-Point 

Transmission Service 

The Transmission Customer shall 

compensate the Transmission Provider 

for Non-Firm Point-To-Point 

Transmission Service up to the sum of 

the applicable charges set forth below: 

(1) Monthly delivery: $ll/KW of 

Reserved Capacity per month. 

(2) Weekly delivery: $ll/KW of 

Reserved Capacity per week. 

(3) Daily delivery: $ll/KW of 

Reserved Capacity per day. 

The total demand charge in any week, 

pursuant to a reservation for Daily 

delivery, shall not exceed the rate 

specified in section (2) above times the 

highest amount in kilowatts of Reserved 

Capacity in any day during such week. 

(4) Hourly delivery: The basic charge 

shall be that agreed upon by the Parties 

at the time this service is reserved and 

in no event shall exceed $ll/MWH. 

The total demand charge in any day, 

pursuant to a reservation for Hourly 

delivery, shall not exceed the rate 

specified in section (3) above times the 

highest amount in kilowatts of Reserved 

Capacity in any hour during such day. 

In addition, the total demand charge in 

any week, pursuant to a reservation for 

Hourly or Daily delivery, shall not 

exceed the rate specified in section (2) 

above times the highest amount in 

kilowatts of Reserved Capacity in any 

hour during such week. 

(5) Discounts: Three principal 

requirements apply to discounts for 

transmission service as follows (1) any 

offer of a discount made by the 

Transmission Provider must be 

announced to all Eligible Customers 

solely by posting on the OASIS, (2) any 

customer-initiated requests for 

discounts (including requests for use by 

one’s wholesale merchant or an 

affiliate’s use) must occur solely by 

posting on the OASIS, and (3) once a 

discount is negotiated, details must be 

immediately posted on the OASIS. For 

any discount agreed upon for service on 

a path, from point(s) of receipt to 

point(s) of delivery, the Transmission 

Provider must offer the same discounted 

transmission service rate for the same 

time period to all Eligible Customers on 

all unconstrained transmission paths 

that go to the same point(s) of delivery 

on the Transmission System. 

Schedule 9—Generator Imbalance 

Service 

Generator Imbalance Service is 

provided when a difference occurs 

between the output of a generator 

located in the Transmission Provider’s 

Control Area and a delivery schedule 

from that generator to (1) another 


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Control Area or (2) a load within the 

Transmission Provider’s Control Area 

over a single hour. The Transmission 

Provider must offer this service when 

Transmission Service is used to deliver 

energy from a generator located within 

its Control Area. The Transmission 

Customer must either purchase this 

service from the Transmission Provider 

or make alternative comparable 

arrangements, which may include use of 

non-generation resources capable of 

providing this service, to satisfy its 

Generator Imbalance Service obligation. 

To the extent the Control Area operator 

performs this service for the 

Transmission Provider, charges to the 

Transmission Customer are to reflect 

only a pass-through of the costs charged 

to the Transmission Provider by that 

Control Area Operator. The 

Transmission Provider may charge a 

Transmission Customer a penalty for 

either hourly generator imbalances 

under this Schedule or hourly energy 

imbalances under Schedule 4 for the 

same imbalance, but not both. 

The Transmission Provider shall 

establish charges for generator 

imbalance based on the deviation bands 

as follows: (i) Deviations within +/¥1.5 

percent (with a minimum of 2 MW) of 

the scheduled transaction to be applied 

hourly to any generator imbalance that 

occurs as a result of the Transmission 

Customer’s scheduled transaction(s) 

will be netted on a monthly basis and 

settled financially, at the end of each 

month, at 100 percent of incremental or 

decremental cost, (ii) deviations greater 

than +/¥1.5 percent up to 7.5 percent 

(or greater than 2 MW up to 10 MW) of 

the scheduled transaction to be applied 

hourly to any generator imbalance that 

occurs as a result of the Transmission 

Customer’s scheduled transaction(s) 

will be settled financially, at the end of 

each month, at 110 percent of 

incremental cost or 90 percent of 

decremental cost, and (iii) deviations 

greater than +/¥7.5 percent (or 10 MW) 

of the scheduled transaction to be 

applied hourly to any generator 

imbalance that occurs as a result of the 

Transmission Customer’s scheduled 

transaction(s) will be settled at 125 

percent of incremental cost or 75 

percent of decremental cost, except that 

an intermittent resource will be exempt 

from this deviation band and will pay 

the deviation band charges for all 

deviations greater than the larger of 1.5 

percent or 2 MW. An intermittent 

resource, for the limited purpose of this 

Schedule is an electric generator that is 

not dispatchable and cannot store its 

fuel source and therefore cannot 

respond to changes in system demand 

or respond to transmission security 

constraints. 

For purposes of this Schedule, 

incremental cost and decremental cost 

represent the Transmission Provider’s 

actual average hourly cost of the last 10 

MW dispatched to supply the 

Transmission Provider’s Native Load 

Customers, based on the replacement 

cost of fuel, unit heat rates, start-up 

costs (including any commitment and 

redispatch costs), incremental operation 

and maintenance costs, and purchased 

and interchange power costs and taxes, 

as applicable. 

Attachment A—Form Of Service Agreement 

For Firm Point-To-Point Transmission 

Service 

1.0 This Service Agreement, dated as of 

llll, is entered into, by and between 

llll (the Transmission Provider), and 

llll (‘‘Transmission Customer’’). 

2.0 The Transmission Customer has been 

determined by the Transmission Provider to 

have a Completed Application for Firm 

Point-To-Point Transmission Service under 

the Tariff. 

3.0 The Transmission Customer has 

provided to the Transmission Provider an 

Application deposit in accordance with the 

provisions of Section 17.3 of the Tariff. 

4.0 Service under this agreement shall 

commence on the later of (l) the requested 

service commencement date, or (2) the date 

on which construction of any Direct 

Assignment Facilities and/or Network 

Upgrades are completed, or (3) such other 

date as it is permitted to become effective by 

the Commission. Service under this 

agreement shall terminate on such date as 

mutually agreed upon by the parties. 

5.0 The Transmission Provider agrees to 

provide and the Transmission Customer 

agrees to take and pay for Firm Point-ToPoint Transmission Service in accordance 

with the provisions of Part II of the Tariff and 

this Service Agreement. 

6.0 Any notice or request made to or by 

either Party regarding this Service Agreement 

shall be made to the representative of the 

other Party as indicated below. 

Transmission Provider: 

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Transmission Customer: 

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

7.0 The Tariff is incorporated herein and 

made a part hereof. 

IN WITNESS WHEREOF, the Parties have 

caused this Service Agreement to be executed 

by their respective authorized officials. 

Transmission Provider: 

By: 

lllllllllllllllllllll

Name 

lllllllllllllllllllll

Title 

lllllllllllllllllllll

Date 

Transmission Customer: 

By: 

lllllllllllllllllllll

Name 

lllllllllllllllllllll

Title 

lllllllllllllllllllll

Date 

Specifications for Long-Term Firm Point-toPoint Transmission Service 

1.0 Term of Transaction: llllllll

Start Date: lllllllllllllll

Termination Date: llllllllllll

2.0 Description of capacity and energy to be 

transmitted by Transmission Provider 

including the electric Control Area in which 

the transaction originates. 

lllllllllllllllllllll

3.0 Point(s) of Receipt: lllllllll

Delivering Party: lllllllllllll

4.0 Point(s) of Delivery: lllllllll

Receiving Party: lllllllllllll

5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): l

6.0 Designation of party(ies) subject to reciprocal service obligation: llllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

7.0 Name(s) of any Intervening Systems 

providing transmission service: llllll

lllllllllllllllllllll

8.0 Service under this Agreement may be 

subject to some combination of the charges 

detailed below. (The appropriate charges for 

individual transactions will be determined in 

accordance with the terms and conditions of 

the Tariff.) 

8.1 Transmission Charge: llllllll

lllllllllllllllllllll

8.2 System Impact and/or Facilities Study 

Charge(s): 

lllllllllllllllllllll

lllllllllllllllllllll

8.3 Direct Assignment Facilities Charge: l

lllllllllllllllllllll

8.4 Ancillary Services Charges: lllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Attachment A–1—Form of Service 

Agreement for the Resale, Reassignment or 

Transfer of Long-Term Firm Point-to-Point 

Transmission Service 

1.0 This Service Agreement, dated as of 

llll, is entered into, by and between 

llll (the Transmission Provider), and 

llll (the Assignee). 

2.0 The Assignee has been determined by 

the Transmission Provider to be an Eligible 

Customer under the Tariff pursuant to which 


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12530 Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 

the transmission service rights to be 

transferred were originally obtained. 

3.0 The terms and conditions for the 

transaction entered into under this Service 

Agreement shall be subject to the terms and 

conditions of Part II of the Transmission 

Provider’s Tariff, except for those terms and 

conditions negotiated by the Reseller, as 

identified below, of the reassigned 

transmission capacity (pursuant to Section 

23.1 of this Tariff) and the Assignee and 

appropriately specified in this Service 

Agreement. Such negotiated terms and 

conditions include: contract effective and 

termination dates, the amount of reassigned 

capacity or energy, point(s) of receipt and 

delivery. Changes by the Assignee to the 

Reseller’s Points of Receipt and Points of 

Delivery will be subject to the provisions of 

Section 23.2 of this Tariff. 

4.0 The Transmission Provider shall 

credit or charge the Reseller, as appropriate, 

for any difference between the price reflected 

in the Assignee’s Service Agreement and the 

Reseller’s Service Agreement with the 

Transmission Provider. 

5.0 Any notice or request made to or by 

either Party regarding this Service Agreement 

shall be made to the representative of the 

other Party as indicated below. 

Transmission Provider: 

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Assignee: 

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

6.0 The Tariff is incorporated herein and 

made a part hereof. 

IN WITNESS WHEREOF, the Parties have 

caused this Service Agreement to be executed 

by their respective authorized officials. 

Transmission Provider: 

By: 

lllllllllllllllllllll

Name 

lllllllllllllllllllll

Title 

lllllllllllllllllllll

Date 

Assignee: 

By: 

lllllllllllllllllllll

Name 

lllllllllllllllllllll

Title 

lllllllllllllllllllll

Date 

Specifications for the Resale, Reassignment 

or Transfer of Long-Term Firm Point-to-Point 

Transmission Service 

1.0 Term of Transaction: llllllll

Start Date: lllllllllllllll

Termination Date: llllllllllll

2.0 Description of capacity and energy to be 

transmitted by Transmission Provider including the electric Control Area in which the 

transaction originates. llllllllll

lllllllllllllllllllll

3.0 Point(s) of Receipt: lllllllll

Delivering Party: lllllllllllll

4.0 Point(s) of Delivery: lllllllll

Receiving Party: lllllllllllll

5.0 Maximum amount of reassigned capacity: lllllllllllllllllll

6.0 Designation of party(ies) subject to reciprocal service obligation: llllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

7.0 Name(s) of any Intervening Systems 

providing transmission service: llllll

lllllllllllllllllllll

8.0 Service under this Agreement may be 

subject to some combination of the charges 

detailed below. (The appropriate charges for 

individual transactions will be determined in 

accordance with the terms and conditions of 

the Tariff.) 

8.1 Transmission Charge: llllllll

lllllllllllllllllllll

8.2 System Impact and/or Facilities Study 

Charge(s): 

lllllllllllllllllllll

lllllllllllllllllllll

8.3 Direct Assignment Facilities Charge: l

lllllllllllllllllllll

8.4 Ancillary Services Charges: lllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

9.0 Name of Reseller of the reassigned 

transmission capacity: 

lllllllllllllllllllll

Attachment B—Form of Service Agreement 

for Non-Firm Point-to-Point Transmission 

Service 

1.0 This Service Agreement, dated as of 

llll, is entered into, by and between 

llll (the Transmission Provider), and 

llll (Transmission Customer). 

2.0 The Transmission Customer has been 

determined by the Transmission Provider to 

be a Transmission Customer under Part II of 

the Tariff and has filed a Completed 

Application for Non-Firm Point-To-Point 

Transmission Service in accordance with 

Section 18.2 of the Tariff. 

3.0 Service under this Agreement shall be 

provided by the Transmission Provider upon 

request by an authorized representative of the 

Transmission Customer. 

4.0 The Transmission Customer agrees to 

supply information the Transmission 

Provider deems reasonably necessary in 

accordance with Good Utility Practice in 

order for it to provide the requested service. 

5.0 The Transmission Provider agrees to 

provide and the Transmission Customer 

agrees to take and pay for Non-Firm PointTo-Point Transmission Service in accordance 

with the provisions of Part II of the Tariff and 

this Service Agreement. 

6.0 Any notice or request made to or by 

either Party regarding this Service Agreement 

shall be made to the representative of the 

other Party as indicated below. 

Transmission Provider: 

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Transmission Customer: 

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

7.0 The Tariff is incorporated herein and 

made a part hereof. 

IN WITNESS WHEREOF, the Parties have 

caused this Service Agreement to be executed 

by their respective authorized officials. 

Transmission Provider: 

By: 

lllllllllllllllllllll

Name 

lllllllllllllllllllll

Title 

lllllllllllllllllllll

Date 

Transmission Customer: 

By: 

lllllllllllllllllllll

Name 

lllllllllllllllllllll

Title 

lllllllllllllllllllll

Date 

Attachment C—Methodology To Assess 

Available Transfer Capability 

The Transmission Provider must include, 

at a minimum, the following information 

concerning its ATC calculation methodology: 

(1) A detailed description of the specific 

mathematical algorithm used to calculate 

firm and non-firm ATC (and AFC, if 

applicable) for its scheduling horizon (same 

day and real-time), operating horizon (day 

ahead and pre-schedule) and planning 

horizon (beyond the operating horizon); 

(2) A process flow diagram that illustrates 

the various steps through which ATC/AFC is 

calculated; and 

(3) A detailed explanation of how each of 

the ATC components is calculated for both 

the operating and planning horizons. 

(a) For TTC, a Transmission Provider shall: 

(i) explain its definition of TTC; (ii) explain 

its TTC calculation methodology; (iii) list the 

databases used in its TTC assessments; and 

(iv) explain the assumptions used in its TTC 

assessments regarding load levels, generation 

dispatch, and modeling of planned and 

contingency outages. 

(b) For ETC, a transmission provider shall 

explain: (i) its definition of ETC; (ii) the 

calculation methodology used to determine 

the transmission capacity to be set aside for 

native load (including network load), and 

non-OATT customers (including, if 

applicable, an explanation of assumptions on 

the selection of generators that are modeled 

in service); (iii) how point-to-point 

transmission service requests are 

incorporated; (iv) how rollover rights are 

accounted for; and (v) its processes for 

ensuring that non-firm capacity is released 


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Federal Register / Vol. 72, No. 50 / Thursday, March 15, 2007 / Rules and Regulations 12531 

properly (e.g., when real time schedules 

replace the associated transmission service 

requests in its real-time calculations). 

(c) If a Transmission Provider uses an AFC 

methodology to calculate ATC, it shall: 

(i) explain its definition of AFC; (ii) 

explain its AFC calculation methodology; 

(iii) explain its process for converting AFC 

into ATC for OASIS posting; (iv) list the 

databases used in its AFC assessments; and 

(v) explain the assumptions used in its AFC 

assessments regarding load levels, generation 

dispatch, and modeling of planned and 

contingency outages. 

(d) For TRM, a Transmission Provider shall 

explain: (i) its definition of TRM; (ii) its TRM 

calculation methodology (e.g., its 

assumptions on load forecast errors, forecast 

errors in system topology or distribution 

factors and loop flow sources); (iii) the 

databases used in its TRM assessments; (iv) 

the conditions under which the transmission 

provider uses TRM. A Transmission Provider 

that does not set aside transfer capability for 

TRM must so state. 

(e) For CBM, the Transmission Provider 

shall state include a specific and selfcontained narrative explanation of its CBM 

practice, including: (i) an identification of the 

entity who performs the resource adequacy 

analysis for CBM determination; (ii) the 

methodology used to perform generation 

reliability assessments (e.g., probabilistic or 

deterministic); (iii) an explanation of whether 

the assessment method reflects a specific 

regional practice; (iv) the assumptions used 

in this assessment; and (v) the basis for the 

selection of paths on which CBM is set aside. 

(f) In addition, for CBM, a Transmission 

Provider shall: (i) explain its definition of 

CBM; (ii) list the databases used in its CBM 

calculations; and (iii) demonstrate that there 

is no double-counting of contingency outages 

when performing CBM, TTC, and TRM 

calculations. 

(g) The Transmission Provider shall 

explain its procedures for allowing the use of 

CBM during emergencies (with an 

explanation of what constitutes an 

emergency, the entities that are permitted to 

use CBM during emergencies and the 

procedures which must be followed by the 

transmission providers’ merchant function 

and other load-serving entities when they 

need to access CBM). If the Transmission 

Provider’s practice is not to set aside transfer 

capability for CBM, it shall so state. 

Attachment D—Methodology for Completing 

a System Impact Study 

To be filed by the Transmission Provider 

Attachment E—Index of Point-To-Point 

Transmission Service Customers 

Customer 

Date of Service Agreement 

Attachment F—Service Agreement for 

Network Integration Transmission Service 

To be filed by the Transmission Provider 

Attachment G—Network Operating 

Agreement 

To be filed by the Transmission Provider 

Attachment H—Annual Transmission 

Revenue Requirement for Network 

Integration Transmission Service 

1. The Annual Transmission Revenue 

Requirement for purposes of the Network 

Integration Transmission Service shall be 

llll. 

2. The amount in (1) shall be effective until 

amended by the Transmission Provider or 

modified by the Commission. 

Attachment I—Index of Network Integration 

Transmission Service Customers 

Customer 

Date of Service Agreement 

Attachment J—Procedures for Addressing 

Parallel Flows 

To be filed by the Transmission Provider 

Attachment K—Transmission Planning 

Process 

The Transmission Provider shall establish 

a coordinated, open and transparent planning 

process with its Network and Firm Point-toPoint Transmission Customers and other 

interested parties, including the coordination 

of such planning with interconnected 

systems within its region, to ensure that the 

Transmission System is planned to meet the 

needs of both the Transmission Provider and 

its Network and Firm Point-to-Point 

Transmission Customers on a comparable 

and nondiscriminatory basis. The 

Transmission Provider’s coordinated, open 

and transparent planning process shall be 

provided as an attachment to the 

Transmission Provider’s Tariff. 

The Transmission Provider’s planning 

process shall satisfy the following nine 

principles, as defined in the Final Rule in 

Docket No. RM05–25–000: coordination, 

openness, transparency, information 

exchange, comparability, dispute resolution, 

regional participation, economic planning 

studies, and cost allocation for new projects. 

The planning process shall also provide a 

mechanism for the recovery and allocation of 

planning costs consistent with the Final Rule 

in Docket No. RM05–25–000. 

The Transmission Provider’s planning 

process must include sufficient detail to 

enable Transmission Customers to 

understand: 

(i) The process for consulting with 

customers and neighboring transmission 

providers; 

(ii) The notice procedures and anticipated 

frequency of meetings; 

(iii) The methodology, criteria, and 

processes used to develop transmission 

plans; 

(iv) The method of disclosure of criteria, 

assumptions and data underlying 

transmission system plans; 

(v) The obligations of and methods for 

customers to submit data to the transmission 

provider; 

(vi) The dispute resolution process; 

(vii) The transmission provider’s study 

procedures for economic upgrades to address 

congestion or the integration of new 

resources; and 

(viii) The relevant cost allocation 

procedures or principles. 

Attachment L—Creditworthiness Procedures 

For the purpose of determining the ability 

of the Transmission Customer to meet its 

obligations related to service hereunder, the 

Transmission Provider may require 

reasonable credit review procedures. This 

review shall be made in accordance with 

standard commercial practices and must 

specify quantitative and qualitative criteria to 

determine the level of secured and unsecured 

credit. 

The Transmission Provider may require the 

Transmission Customer to provide and 

maintain in effect during the term of the 

Service Agreement, an unconditional and 

irrevocable letter of credit as security to meet 

its responsibilities and obligations under the 

Tariff, or an alternative form of security 

proposed by the Transmission Customer and 

acceptable to the Transmission Provider and 

consistent with commercial practices 

established by the Uniform Commercial Code 

that protects the Transmission Provider 

against the risk of non-payment. 

Additionally, the Transmission Provider 

must include, at a minimum, the following 

information concerning its creditworthiness 

procedures: 

(1) a summary of the procedure for 

determining the level of secured and 

unsecured credit; 

(2) a list of the acceptable types of 

collateral/security; 

(3) a procedure for providing customers 

with reasonable notice of changes in credit 

levels and collateral requirements; 

(4) a procedure for providing customers, 

upon request, a written explanation for any 

change in credit levels or collateral 

requirements; 

(5) a reasonable opportunity to contest 

determinations of credit levels or collateral 

requirements; and 

(6) a reasonable opportunity to post 

additional collateral, including curing any 

non-creditworthy determination. 

[FR Doc. E7–3636 Filed 3–14–07; 8:45 am] 

BILLING CODE 6717–01–P 


sroberts on PROD1PC70 with RULES