UNITED STATES OF AMERICA 

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. 

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: (1) strengthen the 

pro forma open-access transmission tariff, or OATT, to ensure that it achieves its original 

purpose of remedying undue discrimination; (2) provide greater specificity to reduce 

opportunities for undue discrimination and facilitate the Commission’s enforcement; and 

(3) increase transparency in the rules applicable to planning and use of the transmission 

system. 

EFFECTIVE DATE: This rule will become effective [insert date 60 days after 

publication in the FEDERAL REGISTER]. 
Docket Nos. RM05-17-000 and RM05-25-000 - 2 -

FOR FURTHER INFORMATION CONTACT: 

Daniel Hedberg (Technical Information) 

Office of Energy Markets and Reliability 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6243 

W. Mason Emnett (Legal Information) 

Office of the General Counsel – Energy Markets 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6540 

Kathleen Barrón (Legal Information) 

Office of the General Counsel – Energy Markets 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6461 

SUPPLEMENTARY INFORMATION

:
 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Preventing Undue Discrimination and Preference 

in Transmission Service 

Docket Nos. RM05-17-000 

 RM05-25-000 

ORDER NO. 890 

FINAL RULE 

(Issued February 16, 2007) 

TABLE OF CONTENTS 

 Paragraph Numbers

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.
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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.
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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.

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.
Docket Nos. RM05-17-000 and RM05-25-000 - 4 -

APPENDIX A: Summary of Compliance Requirements 

APPENDIX B: Commenting Party Acronyms 

APPENDIX C: Pro Forma Open Access Transmission Tariff 
 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

 Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Preventing Undue Discrimination and Preference in 

Transmission Service 

Docket Nos. RM05-17-000 

RM05-25-000 

ORDER NO. 890 

FINAL RULE 

(Issued February 16, 2007) 

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 

 1

 Promoting 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 2 - 

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 

 2

 Preventing Undue Discrimination and Preference in Transmission Service, 

Notice of Proposed Rulemaking, 71 FR 32,636 (Jun. 6, 2006), FERC Stats. & Regs. 

¶ 32,603 (2006). 

3

 The 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.” 
Docket Nos. RM05-17-000 and RM05-25-000 - 3 - 

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 

 4

 Congress 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. No. 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 4 - 

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 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-to-point 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 

 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 5 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 6 - 

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 “pre-confirmed” 

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 above-captioned 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. 

 5

 Preventing 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 7 - 

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 

 6

 Pub. L. No. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. titles 15, 16, 26, 30, 

42, and 43). 
Docket Nos. RM05-17-000 and RM05-25-000 - 8 - 

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 

 7

 Section 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 9 - 

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 market-based 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. Market-based 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 long-term 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 

 8

 See, 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 10 - 

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 

 9

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

10 Pub. L. No. 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 11 - 

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 

 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 12 - 

minimum terms and conditions of non-discriminatory 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 

 13 This 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. 

14 See Order No. 888 at 31,769-70 (noting that the pro forma OATT expressly 

identified certain non-rate 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 13 - 

access services on an agreement to offer non-discriminatory 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, 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 

 15 Order No. 888 at 31,655. 

16 Id. at 31,730-32. 

17 New York v. FERC, 535 U.S. 1 (2002). 
Docket Nos. RM05-17-000 and RM05-25-000 - 14 - 

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 before-the-fact measurement of the availability of transmission service is “difficult,” 

it concluded that it was important to give potential transmission customers “an easy-tounderstand indicator of service availability.”19 Because formal methods did not then 

 18 Open 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). 

19 Order No. 889 at 31,605. 
Docket Nos. RM05-17-000 and RM05-25-000 - 15 - 

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 

 20 Id. at 31,607. 

21 Id.

22 Id. 

23 See Energy Information Administration, Retail Unbundling – U.S. Summary 

(2005), http://www.eia.doe.gov/oil_gas/natural_gas/restructure/state/us.html. 
Docket Nos. RM05-17-000 and RM05-25-000 - 16 - 

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 

 24 Regional 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). 

25 Order No. 2000 at 31,015. 
Docket Nos. RM05-17-000 and RM05-25-000 - 17 - 

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 

 26 Id. at 30,993. 

27 A list of commenter acronyms can be found in Appendix B. 
Docket Nos. RM05-17-000 and RM05-25-000 - 18 - 

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 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 load-serving 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) 

 28 EPAct 2005 sec. 1241 (to be codified at section 219 of the FPA, 16 U.S.C. 

824s). 

29 EPAct 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.

30 EPAct 2005 sec. 1233(a) (to be codified at section 217(b)(4) of the FPA, 

16 U.S.C. 824q). 

31 EPAct 2005 sec. 1221(a) (to be codified at section 216 of the FPA, 16 U.S.C. 

824p). 
Docket Nos. RM05-17-000 and RM05-25-000 - 19 - 

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 

 32 EPAct 2005 sec. 1231 (to be codified at section 211A of the FPA, 16 U.S.C. 

824j-1). 

33 EPAct 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.” 

34 EPAct 2005 sec. 1281 (to be codified at section 220 of the FPA, 16 U.S.C. 

824t). 
Docket Nos. RM05-17-000 and RM05-25-000 - 20 - 

increasing the civil and criminal penalties for violations of Commission-administered 

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, 200536 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 

 35 EPAct 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). 

36 See supra note 5. 

37 Id.
Docket Nos. RM05-17-000 and RM05-25-000 - 21 - 

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. 

 38 Preventing Undue Discrimination and Preference in Transmission Service, 

117 FERC ¶ 61,185 (2006). 
Docket Nos. RM05-17-000 and RM05-25-000 - 22 - 

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 

 39 Order No. 2000 at 31,105. 

40 See 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). 

41 Order No. 2003 at P 11-12. 
Docket Nos. RM05-17-000 and RM05-25-000 - 23 - 

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 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 

load-serving obligation or wholesale transaction that must be consummated quickly – 

seeking redress at the Commission for improperly denied service generally is not time- or 

cost-effective. Instead, Constellation asserts, it is often forced to accept the 

determination of the transmission provider that ATC is not available (even though its 

 42 E.g., APPA, EPSA, East Texas Cooperatives, Fayetteville, NRG, Occidental, 

TAPS, TDU Systems, Williams, Entegra Reply, and NRECA Reply. 

43 See, e.g., Dow, Fayetteville, Occidental, and Williams. 
Docket Nos. RM05-17-000 and RM05-25-000 - 24 - 

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 shortterm 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 point-to-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 first-hand 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 25 - 

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 

 44 See also Southern Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 26 - 

“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 state-regulated, 

vertically-integrated cost-of-service 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 statejurisdictional retail revenues between rate cases. Similarly, Southern, in its reply 

comments, asserts that broad claims of undue discrimination fail to take into 

 45 See, e.g., Entergy Reply, Progress Energy Reply, and Southern Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 27 - 

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 nonISO/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, 

 46 E.g., Indicated New York Transmission Owners, ISO/RTO Council, and 

Northeast Utilities. 
Docket Nos. RM05-17-000 and RM05-25-000 - 28 - 

operates as an impediment to fair and non-discriminatory 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 non-ISO/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 
Docket Nos. RM05-17-000 and RM05-25-000 - 29 - 

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 highcost 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 

 47 Order No. 888 at 31,682. 
Docket Nos. RM05-17-000 and RM05-25-000 - 30 - 

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 

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

49 See, 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_-

7bf20a48324a/2004%20MISO%20SOM%20Report.pdf?action=download&_property=A

ttachment (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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 31 - 

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 

 52 TAPS 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 32 - 

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 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 non-discriminatory access to transmission service. We also believe 

it is appropriate to adopt these reforms by rulemaking, rather than rely on complaints 

 54 See, e.g., Duke and EEI. 
Docket Nos. RM05-17-000 and RM05-25-000 - 33 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 34 - 

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 non-discriminatory manner. Ultimately, 

Williams adds, the lack of transparency and latitude taken by the transmission provider to 
Docket Nos. RM05-17-000 and RM05-25-000 - 35 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 36 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 37 - 

transparency-related reforms should be made after taking into consideration the extent 

and type of data and information that is already provided. 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 38 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 39 - 

54. On the other hand, some commenters dispute the Commission’s assertion in the 

NOPR that vertically-integrated utilities operating in non-RTO 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 vertically-integrated utilities operating under the traditional rate-base, rate-ofreturn 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 verticallyintegrated 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 40 - 

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 verticallyintegrated 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, vertically-integrated 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 41 - 

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 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 

 55 Eric Hirst, U.S. Transmission Capacity: Present Status and Future Prospects

(Aug. 2004), 

http://www.eei.org/industry_issues/energy_infrastructure/transmission/USTransCapacity

10-18-04.pdf (Present Status and Future Prospects). 

56 Present Status and Future Prospects at v. 

57 Brendan 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). 

58 Energy 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 42 - 

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 Mid-America Interconnected Network into WisconsinUpper 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 

 59 Present Status and Future Prospects at v. 

60 U.S. Department of Energy, National Transmission Grid Study at 11, 16-17 

(May 2002), available at www.ferc.gov/industries/electric/indus-act/transmissiongrid.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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 43 - 

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 

 

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. 

62 U.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/doe-congestion-study-2006.pdf. 
Docket Nos. RM05-17-000 and RM05-25-000 - 44 - 

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 

 63 Order No. 888 at 31,794 n.610. 
Docket Nos. RM05-17-000 and RM05-25-000 - 45 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 46 - 

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 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 transparency-related 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. 

 64 Transcript 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 47 - 

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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 48 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 49 - 

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 selfsupplying 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. 

 66 Energy 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 50 - 

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 nonoffending 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 51 - 

resource may not be 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 

redispatch67 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 pre-specified 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 

 67 Although 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 52 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 53 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 54 - 

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 

 68 EPAct 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 55 - 

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 service obligations of the loadserving 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. 

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

70 EPAct 2005 sec. 1223 (to be codified at 42 U.S.C. 16442). 

71 EPAct 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. 

72 EPAct 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 56 - 

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 

 73 EPAct 2005 sec. 1281 (to be codified at 16 U.S.C. 824t). 

74 EPAct 2005 sec. 1284(e)(1) (to be codified at section 316(A) of the FPA, 16 

U.S.C. 825o-1). 
Docket Nos. RM05-17-000 and RM05-25-000 - 57 - 

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 

 75 Enforcement of Statutes, Orders, Rules and Regulations, Policy Statement on 

Enforcement, 113 FERC ¶ 61,068 (2005) (Policy Statement on Enforcement). 
Docket Nos. RM05-17-000 and RM05-25-000 - 58 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 59 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 60 - 

the grid and otherwise ensure that point-to-point service is just, reasonable, and 

not unduly discriminatory. 

• 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-to-point 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-to-point 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-
Docket Nos. RM05-17-000 and RM05-25-000 - 61 - 

term point-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 62 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 63 - 

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 tie-breaker in determining reservation queue 

priority when the transmission provider is willing to discount transmission 

service. 
Docket Nos. RM05-17-000 and RM05-25-000 - 64 - 

• 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 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 Commissionjurisdictional transmission facilities and what constitute state-jurisdictional local 

 76 Order No. 888 at 31,781. 
Docket Nos. RM05-17-000 and RM05-25-000 - 65 - 

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 

 77 Id. at 31,771 (setting forth the seven-factor test). 

78 Id. at 31,781. 

79 Id.

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

81 E.g., Ameren, APPA, North Carolina Commission Reply, PNM-TNMP, and 

Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 66 - 

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. 

 82 See New York v. FERC, 535 U.S. at 28. 
Docket Nos. RM05-17-000 and RM05-25-000 - 67 - 

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 loadserving 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, 

 83 Order No. 888 at 31,745. 

84 Id. at 31,694. 

85 Id.; see pro forma OATT section 2.2. 

86 Order No. 888-A at 30,198. 
Docket Nos. RM05-17-000 and RM05-25-000 - 68 - 

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 APPA89 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-

 87 16 U.S.C. 217(f). 

88 E.g., Ameren, E.ON, Tacoma, Arkansas Commission, EPSA, Southern, and 

TAPS. 

89 APPA 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 69 - 

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 217, EPSA argues that many 

entities other than traditional, vertically-integrated 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. 

 90 E.g., Arkansas Municipal, Constellation, Duke, Salt River, and South Carolina 

E&G. 

91 E.g., Constellation, EPSA, and South Carolina E&G. 
Docket Nos. RM05-17-000 and RM05-25-000 - 70 - 

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 nondiscriminatory manner. According to EPSA, section 217 supports the Commission’s 

paramount statutory mission of ensuring non-discrimination 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 71 - 

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, short-term 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 72 - 

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 

 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 73 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 74 - 

transmission capacity reserved for native load is to be made available (including for study 

and other purposes) to competitive suppliers who wish to 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 75 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 76 - 

and non-discriminatory 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. 

 93 Proposals related to other reforms, such as curtailments and rollovers, are 

discussed in the sections below dealing with each of those issues. 

94 See supra note 72. 
Docket Nos. RM05-17-000 and RM05-25-000 - 77 - 

3. The Types of Transmission Services Offered 

110. In Order No. 888, the Commission required all public utilities to offer, on a nondiscriminatory, open-access basis, firm network service and firm and non-firm point-topoint 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 point-to-point services. 

112. Other commenters, such as AMP-Ohio 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 

 95 E.g., MISO/PJM States, TVA, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 78 - 

Companies reason that allowing transmission providers to move to a contract demandbased 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 state-approved 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. 

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 

 96 Alberta 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 over-consume or buy excess point-to-point service than they would if the 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 79 - 

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 

 

true net cost were reflected. Alberta Intervenors contend that such over-consumption 

reduces access to point-to-point service for other customers. 

97 Alberta Intervenors define “parking” as a network customer reserving point-topoint 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. 

98 Alberta 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 80 - 

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-topoint 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, 

seasonally-shaped, 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 81 - 

concludes that it will not require all transmission providers to offer this service, in 

response to the arguments raised by commenters such as AMP-Ohio 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; 
Docket Nos. RM05-17-000 and RM05-25-000 - 82 - 

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 statemandated 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 

 99 Order No. 888 at 31,654. 
Docket Nos. RM05-17-000 and RM05-25-000 - 83 - 

circumstances and we support voluntary efforts to rely on them,100 the 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 

 100 See 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). 

101 E.g., Santee Cooper, LPPC, TVA, Tacoma, Southern, MISO Transmission 

Owners, and E.ON. 
Docket Nos. RM05-17-000 and RM05-25-000 - 84 - 

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 case-by-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 

 102 Some 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. 

103 The 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, 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 85 - 

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. 

 

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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 86 - 

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 nonrate 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 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. 

Comments 

126. Several commenters ask the Commission to clarify and/or revise the proposal for 

dealing with previously-approved provisions that depart from the existing 
Docket Nos. RM05-17-000 and RM05-25-000 - 87 - 

(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 non-rate 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 nonISO/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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 88 - 

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 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 89 - 

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 two-phased 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 90 - 

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 

currently-proposed 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 91 - 

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 two-tiered 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 contain the revised provisions adopted in the Final Rule, rather than the 

 105 The 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-by-case basis in light 

of the circumstances surrounding the particular transmission provider. 
Docket Nos. RM05-17-000 and RM05-25-000 - 92 - 

transmission provider’s entire pro forma OATT.106 After the submission of their 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 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. 

136. The Commission recognizes that, since the issuance of Order No. 888, some nonISO/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 

 106 As 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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 93 - 

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 previously-approved 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 94 - 

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 previously-approved 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, 

 107 Transmission 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 95 - 

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 

 108 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 website at the following location 

http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp. 
Docket Nos. RM05-17-000 and RM05-25-000 - 96 - 

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 transmission-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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 97 - 

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 nonrate 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 98 - 

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 alreadyapproved 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

 109 See also CMUA Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 99 - 

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 newly-effective provisions of the pro forma

OATT, that are consistent with or superior to the just-filed modifications. 
Docket Nos. RM05-17-000 and RM05-25-000 - 100 - 

147. SPP urges the Commission to affirm that ISOs and RTOs will not be required to 

rejustify their previously-approved 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 101 - 

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 non-discriminatory 

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 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 

vertically-integrated 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 102 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 103 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 104 - 

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, Commissionapproved, 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 transmission-owning members set at six months from 

the date of publication of the Final Rule. 
Docket Nos. RM05-17-000 and RM05-25-000 - 105 - 

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 providers as they are to 

non-independent transmission providers. For example, many ISOs and RTOs use bidbased 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 106 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 107 - 

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 nonpublic utilities to make their systems generally available, it did have the ability and the 

 110 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 website at the following location 

http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp. 

111 These entities are not FPA public utilities and therefore are not subject to the 

Commission’s jurisdiction under sections 205 and 206 of the FPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 108 - 

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 non-public 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 non-public utility may seek a waiver of 

the reciprocity condition from the public utility.112

 112 See Order No. 888-A at 30,285-86. 
Docket Nos. RM05-17-000 and RM05-25-000 - 109 - 

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 non-public 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

 113 For 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 110 - 

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 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 non-public 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 

 

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 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. See Order No. 888-A at 30,289. 

114 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 111 - 

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, nonpublic 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. 

 115 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 112 - 

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. 

 116 See also Public Power Council Reply and Sacramento Reply. 

117 E.g., AWEA, California Commission, Calpine, EEI, MidAmerican, San Diego 

G&E, and Xcel. 
Docket Nos. RM05-17-000 and RM05-25-000 - 113 - 

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 non-discriminatory 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 

 118 E.g., Calpine, MidAmerican, and Xcel. 
Docket Nos. RM05-17-000 and RM05-25-000 - 114 - 

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 non-preferential 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 115 - 

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 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 

 119 See also APPA Reply. 

120 See also CMUA Reply and Santa Clara Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 116 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 117 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 118 - 

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 

 121 Xcel and MidAmerican support EEI’s proposal on this issue. 
Docket Nos. RM05-17-000 and RM05-25-000 - 119 - 

the ISO or RTO. EEI notes, however, that even this action would not require non-public 

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 Department of the Treasury adopted final regulations that in effect provide that 

providing open access transmission does not constitute private use.123 Therefore, EEI 

 122 Citing Order No. 888-A at 30,287. 

123 Treas. Reg. § 1.141-7(g). 
Docket Nos. RM05-17-000 and RM05-25-000 - 120 - 

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. 

 124 EEI 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. 

125 Citing Order No. 888-A at 30,285. 
Docket Nos. RM05-17-000 and RM05-25-000 - 121 - 

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 

non-public 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 122 - 

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 website 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 

 126 According 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. 

127 EEI 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. 

128 EEI 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 123 - 

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 website, the Commission’s 

website, or in some instances a regional entity’s website (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 website. 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 

 

where they are posted, whether they have posted business practices, their contact for 

regional transmission planning, and their ATC methodology 

129 Section 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. 

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

Sacramento Reply, and TANC Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 124 - 

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 nonpublic utility transmission providers that have Commission-approved 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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 125 - 

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-bycase 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 

 131 See Order No. 888-A at 30,289. 
Docket Nos. RM05-17-000 and RM05-25-000 - 126 - 

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. 

 132 See revised 18 CFR 35.28(e)(1)(ii). 
Docket Nos. RM05-17-000 and RM05-25-000 - 127 - 

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, industry-wide 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 

 133 All references to NERC in the context of developing reliability standards are to 

NERC as the Electric Reliability Organization (ERO). 
Docket Nos. RM05-17-000 and RM05-25-000 - 128 - 

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. 

 134 We 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 129 - 

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 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 commenters136 support the NOPR’s proposal to increase 

consistency in the calculation of ATC, several caution the Commission to allow 

 135 The ATC components are total transfer capability (TTC), existing transmission 

commitments (ETC), capacity benefit margin (CBM), and transmission reserve margin 

(TRM). 

136 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 130 - 

flexibility137 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 sub-regional 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 formula143 set forth in NERC’s current ATC definition be 

 137 E.g., Allegheny, Entergy, Indianapolis Power, North Carolina Agencies, and 

NARUC. 

138 E.g., Bonneville, Northwest IOUs, and NorthWestern. 

139 E.g., CAISO. 

140 E.g., Ameren and Tacoma. 

141 E.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. 

142 E.g., TDU Systems and East Texas Cooperatives Reply. 

143 E.g., ATC=TTC - (ETC + CBM + TRM). 
Docket Nos. RM05-17-000 and RM05-25-000 - 131 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 132 - 

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). 

 144 E.g., EEI Reply, NARUC Reply, and Powerex Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 133 - 

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 

 145 Transcript of October 12 Technical Conference at 125-150. 

146 MOD standards refers to Modeling, Data, and Analysis Reliability Standards. 

147 Transcript of October 12 Technical Conference at 149-150. 
Docket Nos. RM05-17-000 and RM05-25-000 - 134 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 135 - 

incur the expense of developing and adopting a new one-size-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 
Docket Nos. RM05-17-000 and RM05-25-000 - 136 - 

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 

 148 For 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 setasides for contingencies while utility B may not. 

149 See Transcript of October 12, 2006 Technical Conference at 125. These 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, network ATC, uses a 

simulator to look not at each path, but each transmission element (line, substation, etc.), 

and run 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 137 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 138 - 

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 

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 ATC-related reliability standards.

 150 The 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 139 - 

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 subregional 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 well-suited 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 140 - 

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, 

 151 E.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. 

152 E.g., EPSA and Williams. 
Docket Nos. RM05-17-000 and RM05-25-000 - 141 - 

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 

 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). 

154 Citing id. at P 20. 

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

Northwest IOUs, Public Power Council, CREPC, Southern, TDU Systems, and 

WestConnect. 
Docket Nos. RM05-17-000 and RM05-25-000 - 142 - 

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 Long-Term 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 

 156 E.g., Utah Municipals and Entegra. 

157 Citing Long-Term AFC/ATC Task Force Final Report (Revised April 14, 

2005), available at http://www.nerc.com/~filez/ltatf.html. 
Docket Nos. RM05-17-000 and RM05-25-000 - 143 - 

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 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. 

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

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 144 - 

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 objectives. 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 145 - 

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 six-month 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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 146 - 

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 

 160 NAESB’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. 

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

162 E.g., ISO/RTO Council, ISO New England, and Pennsylvania Commission. 
Docket Nos. RM05-17-000 and RM05-25-000 - 147 - 

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 non-public 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 

 163 E.g., NRECA and TDU Systems. 

164 E.g., Lassen and Public Power Council. 
Docket Nos. RM05-17-000 and RM05-25-000 - 148 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 149 - 

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 

 165 E.g., Chandley-Hogan, EPSA, PJM, San Diego G&E, and Transparent 

Dispatch Advocates Reply. 

166 E.g., APPA, CMUA, CPA, Duke, EEI, Entergy, LPPC, Public Power Council, 

Sacramento, and WestConnect Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 150 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 151 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 152 - 

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 

 167 E.g., MAPP and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 153 - 

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. 

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 

 168 For example, WECC has a documented open process for establishing TTC for 

the Western Interconnection. 
Docket Nos. RM05-17-000 and RM05-25-000 - 154 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 155 - 

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 

 169 The purpose of MOD-001 is to promote the consistent and uniform application 

of transfer capability calculations among the transmission system users. 

170 By “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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 156 - 

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 

(non-scheduled) 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. 

 171 TRM also includes such things as loop flow and parallel path flow. 
Docket Nos. RM05-17-000 and RM05-25-000 - 157 - 

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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 158 - 

allocated across 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 set-aside 

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-

 172 E.g., Allegheny, Ameren, EEI, Duke, NRECA, TVA, APPA, Bonneville, 

EPSA, FirstEnergy, Indianapolis Power, MidAmerican, Pinnacle, PJM, PGP, PNMTNMP, Public Power Council, Sacramento, Seattle, South Carolina E&G, TANC, TDU 

Systems, and Wisconsin Electric. 
Docket Nos. RM05-17-000 and RM05-25-000 - 159 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 160 - 

reservation decisions from the sole discretion of the vertically-integrated transmission 

provider and instead have them made by the transmission provider/LSE reserve-sharing 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 161 - 

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 set-aside of transfer capability as CBM in the 

development of the rate for point-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 162 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 163 - 

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 set-aside 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-topoint customers, do not pay a transmission charge that includes the cost of the CBM setaside. 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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 164 - 

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 MOD008 and MOD-009173 that 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) 

 173 The MOD-008 and MOD-009 reliability standards document regional TRM 

methodologies and procedures for verifying TRM values. 
Docket Nos. RM05-17-000 and RM05-25-000 - 165 - 

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 hydro-production 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 

 174 E.g., Allegheny, APPA, EEI, EPSA, Exelon, LPPC, MidAmerican, NRECA, 

Northwest IOUs, NorthWestern, Occidental, Pinnacle, Powerex, PNM-TNMP, PPL, 

PJM, PPM, and WestConnect. 

175 Exelon 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 166 - 

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 set-asides 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 

 176 Citing 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=ge

tit&lid=1035. 
Docket Nos. RM05-17-000 and RM05-25-000 - 167 - 

complete statement, to be posted on OASIS, regarding the transmission provider’s 

application of TRM. NERC 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 168 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 169 - 

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. 

 177 The agreement may appropriately restrict the sharing of sensitive information 

with customer personnel that are involved only in transmission functions, as opposed to 

merchant functions. 
Docket Nos. RM05-17-000 and RM05-25-000 - 170 - 

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 nondiscriminatory 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 ATC-related 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. 

 178 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 171 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 172 - 

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. 

 179 E.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. 

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

181 E.g., PJM, EPSA, and Ameren. 
Docket Nos. RM05-17-000 and RM05-25-000 - 173 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 174 - 

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 over-standardization 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 

 182 E.g., Sacramento, Manitoba Hydro, Nevada Companies, and TANC. 
Docket Nos. RM05-17-000 and RM05-25-000 - 175 - 

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-025184 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 

 183 E.g., Sacramento. 

184 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 176 - 

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 long-term ATC calculations that 

are consistent with that used for the 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. 

 185 Final Report on the August 14, 2003 Blackout in the United States and Canada: 

Causes and Recommendations. 
Docket Nos. RM05-17-000 and RM05-25-000 - 177 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 178 - 

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 offpeak 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 179 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 180 - 

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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 181 - 

Comments

300. Alcoa and Powerex emphasize the critical need for ATC to be calculated more 

frequently for constrained facilities. On constrained paths, where transmission equipment 

is stressed to its limits, Alcoa recommends that ATC be calculated on an hourly or realtime 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 182 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 183 - 

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 

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

CAISO, Entergy, Exelon, FirstEnergy, LPPC, MidAmerican, Santee Cooper, Seattle, and 

TAPS. 

187 Under 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 184 - 

providers188 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 RTOs and non-RTOs regions, 

particularly with respect to ATC calculations. In MISO’s view, the Commissionapproved 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. 

 188 SPP 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 185 - 

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 need 

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. 

 189 E.g., Allegheny, Constellation, and Indianapolis Power. 

190 E.g., APPA, Bonneville, TAPS, and Seattle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 186 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 187 - 

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 

 191 We 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 188 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 189 - 

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 

 192 E.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. 

193 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 190 - 

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 

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 

 194 E.g., EEI, PNM-TNMP, Sacramento, Seattle, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 191 - 

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 ATCrelated 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 192 - 

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 administrativelyderived 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 co-owned 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 nonpublic 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 193 - 

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 real-time), operating horizon (day ahead and pre-schedule), and 
Docket Nos. RM05-17-000 and RM05-25-000 - 194 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 195 - 

themselves, which should be 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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 196 - 

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 

 195 WECC 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). 

196 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 197 - 

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 non-discriminatory 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 ATCrelated 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 

 197 For 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 198 - 

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 

 198 Capacity Benefit Margin in Computing Available Transmission Capacity, 

88 FERC ¶ 61,099 (1999) (CBM Order). 
Docket Nos. RM05-17-000 and RM05-25-000 - 199 - 

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. 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 200 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 201 - 

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 

 199 E.g., APPA, Constellation, FirstEnergy, Indianapolis Power, Sacramento, Suez 

Energy NA, TAPS, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 202 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 203 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 204 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 205 - 

(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 

 200 E.g., Powerex, PJM, PPL, Seattle, and Pinnacle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 206 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 207 - 

CBM-related 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 set-aside at least quarterly. 

 201 CBM Order at 61,237. 

202 Id.
Docket Nos. RM05-17-000 and RM05-25-000 - 208 - 

Comments

357. Some commenters support quarterly reevaluation of CBM set-asides.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 setaside for CBM. With respect to TAPS’ concerns over the effort involved in the reevaluation 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 

 203 E.g., EPSA, Sacramento, Santa Clara, Suez Energy NA, and TDU Systems. 

204 CBM Order at 61,237. 
Docket Nos. RM05-17-000 and RM05-25-000 - 209 - 

nature (e.g., installation of a new generator or a long-term outage), quarterly may be too 

frequent, though two years may be too long and may prevent a portion of the CBM setaside 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 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 

 205 The MOD-005 reliability standard establishes the procedure for verifying CBM 

values. 

206 See 18 CFR 37.6(b)(3)(i)(C). 
Docket Nos. RM05-17-000 and RM05-25-000 - 210 - 

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 

reservation-based network service system. 

 207 E.g., Arkansas Commission, CAISO, Constellation, East Texas Cooperatives, 

Exelon, FirstEnergy, LPPC, Morgan Stanley, NRECA, Pinnacle, Powerex, Santa Clara, 

and Suez Energy NA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 211 - 

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 

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

209 E.g., Ameren, EEI, Entergy, MISO, Pinnacle, PJM, PNM-TNMP, Southern, 

TranServ, and TVA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 212 - 

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 

 210 E.g., APPA, East Texas Cooperatives, Suez Energy NA, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 213 - 

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. 

 211 November 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 214 - 

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 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 “marketsensitive” 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 215 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 216 - 

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 

 212 E.g., APPA, Arkansas Commission, Arkansas Municipal, Duke, East Texas 

Cooperatives, MISO, ISO New England, Williams, Nevada Companies, PPL, 

Sacramento, Santa Clara, Suez Energy NA, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 217 - 

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 

 213 E.g., MidAmerican, PacifiCorp, PNM-TNMP, and PJM. 
Docket Nos. RM05-17-000 and RM05-25-000 - 218 - 

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 fiveyear period. Transmission customers therefore would be able to query such requests to 

designate and 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 

 214 See 18 CFR 37.6(a)(6). 
Docket Nos. RM05-17-000 and RM05-25-000 - 219 - 

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 

 215 E.g., APPA, Exelon, PJM, TAPS, TranServ, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 220 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 221 - 

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 

 216 See paragraph 1477, where further detail on using OASIS to request 

designation of network resources is provided. 
Docket Nos. RM05-17-000 and RM05-25-000 - 222 - 

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, machine-readable 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 223 - 

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 (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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 224 - 

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 service-related 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 225 - 

(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 form 

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. 

 217 See 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). 

218 See 18 CFR 388.112-113. 
Docket Nos. RM05-17-000 and RM05-25-000 - 226 - 

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. 

 219 E.g., MidAmerican, Sacramento, Southern, and TVA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 227 - 

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 market-sensitive 

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 

 220 E.g., Nevada Companies, East Texas Cooperatives, PJM, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 228 - 

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 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 

 221 18 CFR 388.113. 
Docket Nos. RM05-17-000 and RM05-25-000 - 229 - 

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 nonaffiliate requests for transmission service that have been made. This posting would also 

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, 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 non-affiliates 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 

 222 E.g., Arkansas Commission, Constellation, MidAmerican, MDEA, Morgan 

Stanley, Nevada Companies, NRECA, Suez Energy NA, and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 230 - 

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 

non-affiliated 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 231 - 

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 needs 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 

 223 E.g., Ameren, Constellation, E.ON, Nevada Companies, NRECA, Powerex, 

Suez Energy NA, TAPS, TDU Systems, and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 232 - 

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 one-day 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 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, non-firm point-to-point or network service). The 

Commission also will require transmission providers to post their underlying load 

 224E.g., E.ON, Entergy, LDWP, and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 233 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 234 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 235 - 

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-to-point transmission because of insufficient capability on its system, it will 

“use due diligence to expand or modify its Transmission System to provide the requested 
Docket Nos. RM05-17-000 and RM05-25-000 - 236 - 

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 

 225 See Order No. 888-A at 30,311. 

226 See id.
Docket Nos. RM05-17-000 and RM05-25-000 - 237 - 

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

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 

 227 Pro 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. 

228 The 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 Website, 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 238 - 

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 selfinterest 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 

 229 Order No. 888 at 31,682. 
Docket Nos. RM05-17-000 and RM05-25-000 - 239 - 

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 pointto-point customers, there is no requirement that the overall transmission planning process 

be open to customers, competitors, and state commissions.232 Rather, transmission 

 230 225 F.3d at 684. 

231 535 U.S. at 8-9 (citation and footnotes omitted). 

232 As 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 Cost-Effectiveness, Security and Reliability” (CECA Report). 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 240 - 

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-the-fact 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 

 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 241 - 

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 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, 

 234 See Order No. 888 at 31,669 (noting that the FPA “fairly bristles” with concern 

for undue discrimination (citing AGD, 824 F.2d at 998). 
Docket Nos. RM05-17-000 and RM05-25-000 - 242 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 243 - 

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 

investor-owned 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 

 235 The one exception is the congestion studies requirement, which is generally 

opposed by transmission providers and supported by customers. 
Docket Nos. RM05-17-000 and RM05-25-000 - 244 - 

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, 

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

237 E.g., Indicated Parties Reply, Old Dominion, NRECA, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 245 - 

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 

 238 See, e.g., Duke and Southern. 

239 See, 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. 

240 Progress Energy also claims that the Commission does not have any 

jurisdiction to mandate regional planning. 
Docket Nos. RM05-17-000 and RM05-25-000 - 246 - 

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 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 longterm planning horizon, broad-based inclusion of reliability, economic, efficiency and 

 241 See also TAPS Reply. 

242 See, e.g., Nevada Companies, New Mexico Attorney General, North Carolina 

Commission Reply, and Southern. 

243 Other 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 247 - 

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 

 244 See 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”). 
Docket Nos. RM05-17-000 and RM05-25-000 - 248 - 

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 

 245 FPA 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.” 

246 The 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 249 - 

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 

 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 250 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 251 - 

Without such a requirement, the more regional RTO or 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 

 247 We 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 252 - 

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 

non-public 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 case-by-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 

 248 FPA 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 253 - 

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 website 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 254 - 

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 

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

NorthWestern, and SCE. 
Docket Nos. RM05-17-000 and RM05-25-000 - 255 - 

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 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 

 250 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 256 - 

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 subregional 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 

 251 E.g., Nevada Companies and NorthWestern. 

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

253 E.g., NRECA, Seminole Reply, TAPS, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 257 - 

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 decisionmaking 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 

 254 This 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 258 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 259 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 260 - 

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. 

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 

 255 E.g., APPA, EEI, Salt River, and Southern. 

256 Other commenters also recognize the need to maintain confidentiality for CEII 

and commercially-sensitive information. E.g., Arkansas Commission, AWEA, California 

Commission, NCPA, NRECA, CREPC, Seattle, TDU Systems, and WAPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 261 - 

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 

 257 Commenters 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 262 - 

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. 

 258 See also East Texas Cooperatives Reply and NRECA Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 263 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 264 - 

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. 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 

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

260 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 265 - 

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 on-going 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-by-case protective orders. In its reply, 

NRECA also asserts that, while it is necessary to protect competitively-sensitive 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 266 - 

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 

 261 NARUC 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. 

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

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

WECC). 
Docket Nos. RM05-17-000 and RM05-25-000 - 267 - 

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 

 264 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 268 - 

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 

 265 See also ISO/RTO Council. 
Docket Nos. RM05-17-000 and RM05-25-000 - 269 - 

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 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 

 266 Much 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 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.
Docket Nos. RM05-17-000 and RM05-25-000 - 270 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 271 - 

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 

 267 See Order No. 888-A at 30,286. 

268 We believe this same approach should also apply to public utilities that have 

obtained waivers of the Standards of Conduct. 
Docket Nos. RM05-17-000 and RM05-25-000 - 272 - 

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 

 269 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 273 - 

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 

 270 Transmission 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 websites, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 274 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 275 - 

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 

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

272 E.g., PJM and ISO-New England. 

273 See 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/demandresponse.pdf#xml=http://search.atomz.com/search/pdfhelper.tk?sp_o=1,100000,0. 
Docket Nos. RM05-17-000 and RM05-25-000 - 276 - 

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. 

 274 The 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. 

275 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 277 - 

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 non-public utilities. EEI maintains that similarlysituated 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-topoint 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 

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

277 TVA 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 278 - 

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 performed, and how and why proposed upgrades 

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

279 E.g., NCPA and TDU Systems. 

280 See also Bonneville, California Commission, Imperial, NCPA, and Seattle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 279 - 

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. 

 281 E.g., New Jersey Board, Ohio Power Siting Board, and WIRES. 
Docket Nos. RM05-17-000 and RM05-25-000 - 280 - 

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-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 281 - 

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 similarly-situated 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-

 282 E.g., California Commission, NCPA, CREPC, Salt River, Seattle, and WAPA. 

283 E.g., Duke and Imperial. 

284 See also MidAmerican, Progress Energy, and Xcel. 
Docket Nos. RM05-17-000 and RM05-25-000 - 282 - 

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 

 285 See also NRECA Reply and Old Dominion. 

286 TAPS 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 283 - 

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 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. 

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

288 As 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 284 - 

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. 

 289 Additionally, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 285 - 

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 

 290 E.g., APPA, Bonneville, California Commission, Imperial, and NCPA. 

291 E.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. 

292 E.g., Allegheny, Nevada Companies, Pinnacle, and Southern. Xcel, however, 

does not believe any dispute resolution process is required in the OATT. 

293 See also Duke and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 286 - 

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 

 294 We 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 287 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 288 - 

provider 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 

“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 
Docket Nos. RM05-17-000 and RM05-25-000 - 289 - 

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 

 295 TAPS 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 290 - 

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 currently-existing 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 

 296 NRECA’s comments on regional planning are consistent with those of TDU 

Systems. 

297 See also MidAmerican Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 291 - 

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 municipally-owned 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 

 298 See 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). 

299 Eg., California Commission, Imperial, and Salt River. 
Docket Nos. RM05-17-000 and RM05-25-000 - 292 - 

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 well-situated 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 regional participation, because 

 300 See 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. 

301 E.g., Allegheny, Constellation, and Duke. 
Docket Nos. RM05-17-000 and RM05-25-000 - 293 - 

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 

 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 sub-regional groups have facilitated the planning of their 

member providers. 
Docket Nos. RM05-17-000 and RM05-25-000 - 294 - 

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 

 303 E.g., ColumbiaGrid, MidAmerican, Nevada Companies, NorthWestern, 

Pinnacle, and Xcel. 

304 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 295 - 

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 sub-region’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 

 305 Public 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. 

306 WAPA 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. 

307 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 296 - 

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 Californiawide sub-regional 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. 

 308 Anaheim 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 297 - 

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 sub-regional planning in that region – the ColumbiaGrid group and 

the Northern Tier Transmission Group – but it is not yet clear how such groups intend to 

coordinate with each other. 

 309 E.g., Bonneville, ColumbiaGrid, PGP, Public Power Council, and Seattle. 

APPA also notes its members’ support for the sub-regional processes in the Northwest. 
Docket Nos. RM05-17-000 and RM05-25-000 - 298 - 

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. 

 310 See also TDU Systems Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 299 - 

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, FMPA311 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 

 311 We note that FMPA filed joint comments on behalf of itself and the Midwest 

Municipal Transmission Group. 
Docket Nos. RM05-17-000 and RM05-25-000 - 300 - 

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 

 312 See also Seminole Reply. 

313 As 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 301 - 

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 region-wide 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 302 - 

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. 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 subregions. In very large regions, there may well be both sub-regional and regional 
Docket Nos. RM05-17-000 and RM05-25-000 - 303 - 

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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 304 - 

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 

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

Cooperatives, Entegra, NCPA, CREPC, Southwestern Coop, TDU Systems, and WIRES. 
Docket Nos. RM05-17-000 and RM05-25-000 - 305 - 

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 

 315 E.g., American Transmission, EEI, Progress Energy, and Southern. 

316 Entegra, 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. 

317 E.g., Imperial, MidAmerican, Nevada Companies, NorthWestern, Pinnacle, 

Salt River, SWAT, WestConnect, and Xcel. 
Docket Nos. RM05-17-000 and RM05-25-000 - 306 - 

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 interconnectionwide congestion studies conducted by WECC. Tacoma notes that ColumbiaGrid is 

 318 Others assert that the DOE studies will be useful but not necessarily duplicative 

of the congestion study principle. E.g., APPA and Salt River. 

319 Bonneville agrees that the costs of congestion itself are not readily available to 

transmission providers and that customers are better positioned to determine this. 
Docket Nos. RM05-17-000 and RM05-25-000 - 307 - 

considering the 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. 

 320 E.g., Allegheny, FirstEnergy, Indianapolis Power, and PSEG. 
Docket Nos. RM05-17-000 and RM05-25-000 - 308 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 309 - 

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 

 321 See also Indicated Parties Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 310 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 311 - 

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-by-request basis. We also find that they are consistent with the requirement to 

provide comparable service. 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 312 - 

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 

 322 See PJM Interconnection, L.L.C., 117 FERC ¶ 61,218 (2006), reh’g pending. 
Docket Nos. RM05-17-000 and RM05-25-000 - 313 - 

impose a costly study requirement that is unrelated to the real-world 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 314 - 

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 

 323 The 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. 

324 This 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 315 - 

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 interconnection or transmission service under the pro forma OATT. Rather, 

we contemplate that any such studies conducted pursuant to this principle, as explained 
Docket Nos. RM05-17-000 and RM05-25-000 - 316 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 317 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 318 - 

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 

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

SCE, and Southern. 

326 E.g., APPA, Arkansas Commission, PGP, Santee Cooper, Southwestern Coop, 

and Sacramento. 

327 E.g., E.ON, National Grid and WIRES. 
Docket Nos. RM05-17-000 and RM05-25-000 - 319 - 

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 

 328 E.g., AWEA, NCEMC, NCPA, NRECA, Seattle, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 320 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 321 - 

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. 

 329 Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 589 (1945). 
Docket Nos. RM05-17-000 and RM05-25-000 - 322 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 323 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 324 - 

providers have conducted non-transparent 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. 

 330 See 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. 

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

332 E.g., APPA, Bonneville, California Commission, Duke, Indianapolis Power, 

NCEMC, NRECA, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 325 - 

565. EEI argues against an independence requirement, seeing no need to require nonRTO/ISO transmission providers to engage independent third parties to oversee the 

planning process.333 EEI believes the 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. 

 333 TVA believes that the levels of independence practiced in NERC and NAESB 

and the implementation and administration of those standards by the regional entities 

(such as SERC) are adequate and appropriate. 
Docket Nos. RM05-17-000 and RM05-25-000 - 326 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 327 - 

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

 334 E.g., American Transmission, Duke, and Progress Energy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 328 - 

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 nonRTO 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 

 335 Similar 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 329 - 

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, 

 336 NYAPP, on the other hand, urges the Commission to require planning for all 

transmission facilities, not just bulk power facilities. 

337 E.g., AWEA, California Commission, and Project for Sustainable FERC 

Energy Policy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 330 - 

such as retail resource needs, in the planning 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 second-guessed, 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 

 338 As 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. 

339 We 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.
Docket Nos. RM05-17-000 and RM05-25-000 - 331 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 332 - 

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 

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

341 E.g., APPA, East Texas Cooperatives, Seattle, and TDU Systems. 

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

343 E.g., Arkansas Municipal, Project for Sustainable FERC Energy Policy, and 

Southwestern Coop. 
Docket Nos. RM05-17-000 and RM05-25-000 - 333 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 334 - 

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 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

 344 E.g., Duke, Indianapolis Power, MidAmerican, Progress Energy, PSEG, South 

Carolina E&G, and SPP. 

345 E.g., Southern and South Carolina E&G. 
Docket Nos. RM05-17-000 and RM05-25-000 - 335 - 

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. 

 346 E.g., Bonneville, NRECA, and CREPC. 
Docket Nos. RM05-17-000 and RM05-25-000 - 336 - 

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. 

 347 E.g., APPA, East Texas Cooperatives Reply, FMPA, NCPA, TAPS, TDU 

Systems, Utah Municipals, and WIRES. 
Docket Nos. RM05-17-000 and RM05-25-000 - 337 - 

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 Commission-

 348 E.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. 

349 APPA, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 338 - 

jurisdictional owners and urge the Commission to make clear that both jurisdictional and 

nonjurisdictional owners would be subject to the same requirements for service over 

jointly-owned 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, 

 350 E.g., Bonneville, California Commission, and CREPC. Bonneville stresses that 

any jointly-owned facilities should have a single operator. 
Docket Nos. RM05-17-000 and RM05-25-000 - 339 - 

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 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 co-owners. 

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 

 351 Similar 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 340 - 

should not, as suggested by Duke, condition the participation of a nonjurisdictional entity 

in a jointly-owned 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 jointly-owned 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 jointly-owned 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 341 - 

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. 

 352 As 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 342 - 

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. 

 353 E.g., EEI, MISO, NorthWestern, PSEG, and Tacoma. 
Docket Nos. RM05-17-000 and RM05-25-000 - 343 - 

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 

 354 Related 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. 

355 EEI 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. 

356 E.g., APPA, Arkansas Commission, AWEA, CREPC, Sacramento, and Seattle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 344 - 

be overly burdensome and would divert attention away from the fundamentals of prudent 

planning; and Bonneville notes that market participants often make requests 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 note 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.

 357 E.g., New Jersey Board, Ohio Power Siting Board, and WIRES. 
Docket Nos. RM05-17-000 and RM05-25-000 - 345 - 

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 planningrelated 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; 

 358 E.g., APPA, NRECA, Old Dominion, and Seattle. APPA also suggests OASIS 

posting. 
Docket Nos. RM05-17-000 and RM05-25-000 - 346 - 

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 nondiscriminatory 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 347 - 

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 

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

360 E.g., Arkansas Municipal, TAPS, and TDU Systems 
Docket Nos. RM05-17-000 and RM05-25-000 - 348 - 

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 non-RTO 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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 349 - 

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 

commenters362 go further to assert that the Commission require the use of locational 

marginal pricing (LMP) as a part of OATT reform. Other commenters363 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 commenters364 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 

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

362 E.g., Morgan Stanley and Steel Manufacturers Associations. 

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

364 E.g., EPSA and Chandley-Hogan. 
Docket Nos. RM05-17-000 and RM05-25-000 - 350 - 

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 all-inclusive, “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 
Docket Nos. RM05-17-000 and RM05-25-000 - 351 - 

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 non-discriminatory 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 352 - 

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 non-RTOs/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 
Docket Nos. RM05-17-000 and RM05-25-000 - 353 - 

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 inter-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 
Docket Nos. RM05-17-000 and RM05-25-000 - 354 - 

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 

 365 E.g., LPPC, Entergy, and Sacramento. 
Docket Nos. RM05-17-000 and RM05-25-000 - 355 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 356 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 357 - 

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 non-RTO 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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 358 - 

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 real-time 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 359 - 

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 

 366 See, 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.

368 Order No. 888 at 31,703. 

369 Id.

370 See Id. at 31,960. 

371 Order No. 888-A at 30,230. 
Docket Nos. RM05-17-000 and RM05-25-000 - 360 - 

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 

 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 361 - 

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 

 

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.

378 See, 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 362 - 

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 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 

 379 See 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). 

380 Order No. 888-A at 30,230. 

381 Id.

382 Id. 
Docket Nos. RM05-17-000 and RM05-25-000 - 363 - 

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 

 383 See, 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). 

384 Order 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 364 - 

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 

 386 The 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)). 

387 Under existing Commission policy, a transmission provider may only charge a 

transmission customer for the penalty percent adder to the incremental cost for either a 

hourly generator imbalances or a 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. 

388 See 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)). 
Docket Nos. RM05-17-000 and RM05-25-000 - 365 - 

overdeliveries range from 90 percent389 of system decremental cost to 50 percent390 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 

 389 See Entergy Services, Inc., 90 FERC ¶ 61,272 (2000) (concerning various 

generator imbalance agreements). 

390 See Duke Delegated Letter Order. 
Docket Nos. RM05-17-000 and RM05-25-000 - 366 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 367 - 

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 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 

 391 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 368 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 369 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 370 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 371 - 

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 

market-clearing 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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 372 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 373 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 374 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 375 - 

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 first-tier 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 

 392 E.g., NorthWestern, Fertilizer Institute, and Geothermal Producers. 
Docket Nos. RM05-17-000 and RM05-25-000 - 376 - 

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 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 third-tier deviation band and 

 393 E.g., Morgan Stanley, Northwest IOUs, Steel Manufacturers Association, and 

TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 377 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 378 - 

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 commenters394 argue on reply that it would be inappropriate for the 

Commission to grandfather existing imbalance provisions. In its reply comments, Entegra 

 394 E.g., Fertilizer Institute, Entegra, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 379 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 380 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 381 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 382 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 383 - 

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. 

 395 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 384 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 385 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 386 - 

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 

 396 See 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 under-delivery or overuse of energy,” or “persistent over-generation 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 387 - 

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. 

 397 E.g., Imperial District Irrigation, Progress Energy and Ameren. 
Docket Nos. RM05-17-000 and RM05-25-000 - 388 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 389 - 

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 commitment398 costs, to the extent additional commitments are 

needed.399 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. 

 398 The 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). 

399 The 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 maintenance costs, 

and purchased and interchange power costs and taxes. 
Docket Nos. RM05-17-000 and RM05-25-000 - 390 - 

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 realtime 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 

 400 E.g., Allegheny, Ameren, Indicated New York Transmission Owners, and 

FirstEnergy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 391 - 

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 under-deliveries. 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 392 - 

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 under-deliveries. 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 non-intermittent 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 market-based 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 393 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 394 - 

commitment costs such as start-up costs or minimum run times. EEI argues that if 

transmission providers could not recover such costs through imbalance 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 395 - 

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. 

 401 To 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 396 - 

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 case-by-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, 

 402 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 397 - 

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 

 403 E.g., Entergy, Allegheny, Progress Energy, Public Power Council, South 

Carolina E&G, PGP, and Ameren. 
Docket Nos. RM05-17-000 and RM05-25-000 - 398 - 

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 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’ 
Docket Nos. RM05-17-000 and RM05-25-000 - 399 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 400 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 401 - 

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 return-in-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 

 404 For 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 402 - 

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. 

 

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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 403 - 

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 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 

 406 E.g., Ameren, FirstEnergy, Xcel, Suez Energy NA, Morgan Stanley, 

Sacramento, TDU Systems, and Utah Municipals. 
Docket Nos. RM05-17-000 and RM05-25-000 - 404 - 

(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 
Docket Nos. RM05-17-000 and RM05-25-000 - 405 - 

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. 

 407 E.g., Entergy, Pinnacle, Indianapolis Power, and Indicated New York 

Transmission Owners. 
Docket Nos. RM05-17-000 and RM05-25-000 - 406 - 

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 real-time. Entergy argues that a netting approach, however, 

would provide an incentive for a generator to over-generate 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 under-generation 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 407 - 

be measured and settled financially on an hourly or, at least, an on-peak/off-peak 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. Allowing transmission 
Docket Nos. RM05-17-000 and RM05-25-000 - 408 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 409 - 

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 within-hour 

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 

 408 E.g., TVA, South Carolina E&G, and International Transmission. 
Docket Nos. RM05-17-000 and RM05-25-000 - 410 - 

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 withinhour 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 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 411 - 

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 tenminute intervals rather than integrated over an hour. These ten-minute 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 412 - 

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. 

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. 

 410 See Entergy Services, Inc., 102 FERC ¶ 61,014 (2003) and Entergy Services, 

Inc., 111 FERC ¶ 61,314 (2005). 

411 See Order No. 2003 at P 335. 

412 See pro forma LGIA Article 4.3.1 
Docket Nos. RM05-17-000 and RM05-25-000 - 413 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 414 - 

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 

 413 See 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). 

414 See Carolina Power & Light Co., 97 FERC ¶ 61,048 at 61,279 (2001). 
Docket Nos. RM05-17-000 and RM05-25-000 - 415 - 

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 non-offending 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, 

 415 Id.
Docket Nos. RM05-17-000 and RM05-25-000 - 416 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 417 - 

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 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-by-case 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 joint-planning requirement for credits for new facilities 

 416 Order No. 888 at 31,742; Order No. 888-A at 30,271. 
Docket Nos. RM05-17-000 and RM05-25-000 - 418 - 

constructed by network customers is supported by a cross-section 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. 

 417 E.g., Allegheny, East Texas Cooperatives, ELCON, Exelon, FMPA, MDEA, 

MidAmerican, MISO, Suez Energy NA, Tacoma, TAPS, and Utah Municipals. 
Docket Nos. RM05-17-000 and RM05-25-000 - 419 - 

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 cross-purposes 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 420 - 

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 nonOATT (i.e., grandfathered bundled agreements) contracts. PGP supports the new rules 

 418 E.g., Allegheny, EEI, Exelon, MISO, Nevada Companies, South Carolina 

E&G, Suez Energy NA, and Tacoma. 

419 E.g., Allegheny, Ameren, and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 421 - 

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. 

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

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

422 E.g., East Texas Cooperatives, NRECA, TAPS, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 422 - 

739. NRECA questions the Commission’s statement in the NOPR that, in order to 

satisfy the integration 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 

 423 NRECA 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 423 - 

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 

analysis428 to one asking the Commission to eliminate the comparability component in 

favor of an integration-only analysis.429 

 425 114 FERC ¶ 61,027 at P 42 (2006), appeal docketed, No. 06-1090 (D.C. Cir. 

Mar. 10, 2006). 

426 NOPR at P 256. 

427 Id.

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

429 Entergy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 424 - 

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., a 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 

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

431 NRECA 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 425 - 

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 

 432 MDEA 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 426 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 427 - 

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 

 433 E.g., Entergy, Exelon, and Utah Municipals. 
Docket Nos. RM05-17-000 and RM05-25-000 - 428 - 

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 

 434 See NOPR at P 256. 
Docket Nos. RM05-17-000 and RM05-25-000 - 429 - 

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 

 435 See 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. 

436 The 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 430 - 

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, 

 

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). 

437 E.g., APPA, FMPA, MDEA, NRECA, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 431 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 432 - 

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 

 438 See East Texas Electric Cooperative v. Central and South West Services, Inc., 

114 FERC ¶ 61,027 (2006). 

439 E.g., Allegheny, EEI, MidAmerican, and Nevada Companies. 
Docket Nos. RM05-17-000 and RM05-25-000 - 433 - 

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 customer-owned facilities, EEI continues, since the existence of customerowned 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 434 - 

essentially re-justifying 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 

customer-owned 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 

 440 E.g., Allegheny, EEI, Exelon, and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 435 - 

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 filed-rate 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 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 

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

111 FERC ¶ 61,307 (2005). 
Docket Nos. RM05-17-000 and RM05-25-000 - 436 - 

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-to-point customers that own transmission facilities.442 

 442 E.g., APPA, Bonneville, EEI, Exelon, FirstEnergy, Nevada Companies, and 

TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 437 - 

APPA argues that if the frequency of cases seeking credits for facilities owned by pointto-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-to-point 

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 

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

444 Citing Nevada Power Co., 101 FERC ¶ 61,036 at P 8 (2002). 
Docket Nos. RM05-17-000 and RM05-25-000 - 438 - 

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-topoint 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-to-point 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-to-point 

customer meets all the criteria for credits, we will continue to address such situations on a 

fact-specific, case-by-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 

 445 Order No. 888 at 31,742; Order No. 888-A at 30,271. 

446 E.g., Indicated New York Transmission Owners, ISO New England, PJM, and 

SPP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 439 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 440 - 

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. 

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 decision448 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. 

 447 For example, NYISO’s tariff provides that a facilities study will contain a nonbinding 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. 

448 East 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) 
Docket Nos. RM05-17-000 and RM05-25-000 - 441 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 442 - 

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 

 449 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). 

450 See Order No. 888 at 31,696; pro forma OATT section 23.1. 
Docket Nos. RM05-17-000 and RM05-25-000 - 443 - 

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 

 451 Id. at 31,740. 

452 Order No. 888-A at 30,224. 
Docket Nos. RM05-17-000 and RM05-25-000 - 444 - 

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) should the Commission establish a new quarterly reporting process with a 

 453 The 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 445 - 

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 

 454 E.g., Allegheny, AWEA, Constellation, EEI, Entegra, EPSA, Exelon, Morgan 

Stanley, PPL, Seattle, Suez Energy NA, and TranServ. 

455 Citing Natural Gas Pipeline Negotiated Rate Policies and Practices, 114 FERC 

¶ 61,034 (2006) (Brownell, Comm’r concurring). 
Docket Nos. RM05-17-000 and RM05-25-000 - 446 - 

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 

 456 E.g., APPA, AWEA, NRECA, Seattle, TAPS, and TDU Systems. 

457 Citing Public Service Electric & Gas Company, 78 FERC ¶ 61,119 at 61,455 

(1997) (granting market-based rate authority based in part on the adequate “mitigation of 

market power” as evidenced by a pro forma OATT). 
Docket Nos. RM05-17-000 and RM05-25-000 - 447 - 

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 resell 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 

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

Manitoba Hydro, MidAmerican, Progress Energy, and Salt River. 

459 E.g., MidAmerican, PNM-TNMP and South Carolina E&G. 
Docket Nos. RM05-17-000 and RM05-25-000 - 448 - 

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. 

 460 E.g., EEI, Entergy, MidAmerican, PNM-TNMP, Progress Energy, Southern, 

and South Carolina E&G. 

461 E.g., Community Power Alliance, Entergy, Imperial, Manitoba Hydro, Salt 

River, South Carolina E&G, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 449 - 

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 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 

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

463 See Order No. 888 at 31,697. 

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

465 E.g., EEI, Entergy and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 450 - 

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 

 466 E.g., Entegra and NorthWestern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 451 - 

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 non-affiliates 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 

 467 E.g., Community Power Alliance, EEI, FirstEnergy, Imperial, Northwest IOUs, 

Southern, and TVA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 452 - 

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 

 468 E.g., Alcoa, APPA, International Transmission, Nevada Companies, NRECA, 

PJM, Public Power Council, TAPS, and WAPA. 

469 E.g., APPA, Nevada Companies, Northwest IOUs, NRECA, PJM, TAPS, and 

WAPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 453 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 454 - 

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 

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’ 

 470 E.g., APPA, International Transmission, NRECA, Public Power Council, and 

Seattle. 

471 E.g., Alcoa, APPA, Bonneville, TAPS, and WAPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 455 - 

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 

 472 Citing 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). 

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

474 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 456 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 457 - 

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 

 475 E.g., Alcoa, APPA, Manitoba Hydro, PGP, Sacramento, and Seattle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 458 - 

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 procompetitive policy by permitting RTO/ISO transmission providers to offer firm point-topoint 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 point-to-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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 459 - 

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 

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

477 E.g., EEI, Entergy, Nevada Companies, PNM-TNMP, South Carolina E&G, 

Southern, and TVA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 460 - 

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 MWmonth, 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 

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

479 E.g., PJM, PNM-TNMP, and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 461 - 

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 

 480 E.g., Allegheny, Morgan Stanley, NAESB, Seattle, and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 462 - 

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 offsystem 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 

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

482 E.g., APPA, Powerex, and SPP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 463 - 

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 pointto-point customers. Powerex and SPP also ask the Commission to set out clear rules, 

including timelines, for releasing unused transmission capacity for non-firm 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 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 

 483 Order No. 888 at 31,696. 
Docket Nos. RM05-17-000 and RM05-25-000 - 464 - 

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 non-affiliated 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 

 484 Because 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. 

485 Order No. 888 at 31,696-97; Order No. 888-A at 30,219-25. 

486 Order No. 888 at 31,697. 
Docket Nos. RM05-17-000 and RM05-25-000 - 465 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 466 - 

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 

 487 As 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 467 - 

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 over-reserve 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 

 488 Order No. 888 at 31,693. 

489 See Southwestern Public Service Company, 80 FERC ¶ 61,245 at 61,905 

(1997). 

490 Moreover, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 468 - 

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 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 

 491 Order No. 637-A at 31,595. 
Docket Nos. RM05-17-000 and RM05-25-000 - 469 - 

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
Docket Nos. RM05-17-000 and RM05-25-000 - 470 - 

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 

 492 Our 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. 

493 See Order No. 888 at 31,697. 
Docket Nos. RM05-17-000 and RM05-25-000 - 471 - 

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 

 494 See Order No. 888 at 31,697 n.394; Order No. 888-A at 30,224 n.151. 

495 The 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. 

496 As 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 472 - 

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 alreadyapproved 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. 

 

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. 

497 To the extent the assignee desires to change its points of receipt or delivery, the 

limitations set forth in section 23.2 shall apply. 

498 See 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 473 - 

The Commission directs that this quarterly report be submitted electronically in 

spreadsheet format 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 

 499 The 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/docs-filing/eqr.asp. 

500 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 474 - 

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 Union501 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 shortterm 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 

 

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). 

502 Order No. 637-A at 31,558-72. 
Docket Nos. RM05-17-000 and RM05-25-000 - 475 - 

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 reassignment-related 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 Hotline504 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 

 503 Interstate Natural Gas Association of America v. FERC, 285 F.3d 18 (D.C. Cir. 

2002). 

504 Market 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/contact-us/enforce-hot.asp.

 
Docket Nos. RM05-17-000 and RM05-25-000 - 476 - 

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 

 505 Order No. 889 at 31,625. 

506 See Order No. 2001 at P 94-129. 
Docket Nos. RM05-17-000 and RM05-25-000 - 477 - 

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, 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 

 507 Order No. 888 at 31,696; Order No. 888-A at 30, 223 
Docket Nos. RM05-17-000 and RM05-25-000 - 478 - 

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 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 479 - 

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 non-compliance. 

 509 E.g., APPA and Bonneville. 

510 E.g., MidAmerican, Southern, and PNM-TNMP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 480 - 

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 point-to-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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 481 - 

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 

 511 E.g., APPA, TAPS, TDU Systems, and EEI Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 482 - 

secondary non-firm 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 from that same generator using point-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 483 - 

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 

 512 Arizona 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-to-point service. 
Docket Nos. RM05-17-000 and RM05-25-000 - 484 - 

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 noncompliance.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-of-date given the dynamic manner by 

which trading patterns and practices evolve. We believe that Commission actions, such 

 513 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 485 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 486 - 

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 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 487 - 

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 off-system 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-to-point 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 

 514 See MidAmerican Energy Co., 112 FERC ¶ 61,346 (2005); PacifiCorp, 

118 FERC ¶ 61,026 (2007). 

515 See Order No. 888-A at 30,216-17. 

516 See id. at 30,217 
Docket Nos. RM05-17-000 and RM05-25-000 - 488 - 

service agreement with the transmission provider is deemed to have executed the 

transmission provider’s form of service agreement for point-to-point 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 off-system sale. TAPS 

asks the Commission to clarify that a transmission provider that inappropriately uses 

 517 E.g., APPA and PNM-TNMP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 489 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 490 - 

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 off-system 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 

 518 E.g., EEI, Bonneville, MidAmerican, Nevada Companies, and PNM-TNMP 

Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 491 - 

transmission service is equal to twice the standard rate for transmission service. EEI 

recommends that the Commission establish a policy that a 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 

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

520 E.g., APPA, AWEA, TAPS, and TDU Systems Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 492 - 

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 

 521 E.g., NRECA, Nevada Companies, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 493 - 

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-to-point. 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 

 522 There 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 pointto-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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 494 - 

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-to-point rate for the period of unreserved use, as defined above.523 

 523 Allegheny Power System, Inc., 80 FERC ¶ 61,143 at 61,545-46 (1997) 

(Allegheny). 
Docket Nos. RM05-17-000 and RM05-25-000 - 495 - 

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-to-point 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 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 a 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 496 - 

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 

 524 An 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 497 - 

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 nonoffending 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 

 525 E.g., APPA, ELCON, Entegra, TAPS, TDU Systems, Sacramento, and Seattle. 

526 Entegra cites Carolina Power & Light Co. and Florida Power Corp., 103 FERC 

¶ 61,209 at P 24 (2003) (Carolina Power & Light). 
Docket Nos. RM05-17-000 and RM05-25-000 - 498 - 

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 

 527 E.g., EEI, MidAmerican, Nevada Companies, and PNM-TNMP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 499 - 

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 one-time 

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 onetime 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 

 528 E.g., EEI, Suez Energy NA, Sacramento, TAPS, and Wisconsin Electric. 

529 E.g., Ameren and PNM-TNMP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 500 - 

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 

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 non-offending, 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 501 - 

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 non-affiliated 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 502 - 

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 

 530 As 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. 

531 Regulation 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 non-penalty 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....”). 
Docket Nos. RM05-17-000 and RM05-25-000 - 503 - 

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 nonoffending, 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 504 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 505 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 506 - 

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 

 532 E.g., ISO New England, PJM, MISO, SPP, and Ameren. 
Docket Nos. RM05-17-000 and RM05-25-000 - 507 - 

transmission provider to pay “non-offending” customers when the provider incurs 

operational penalties is self-defeating, 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 non-offending customers. A non-
Docket Nos. RM05-17-000 and RM05-25-000 - 508 - 

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 

 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). 

534 Southwest 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 509 - 

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 

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.

 535 Southwest Power Pool, Inc., 112 FERC ¶ 61,319 at P 33 (2005). 

536 See Southwest Power Pool, Inc., 98 FERC ¶ 61,256 at 62,026, reh’g denied in 

pertinent part, 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.”). 

537 E.g., APPA, Bonneville, and Public Power Council. 
Docket Nos. RM05-17-000 and RM05-25-000 - 510 - 

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 

 538 E.g., ELCON, Constellation, FirstEnergy, NorthWestern, PGP, TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 511 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 512 - 

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. 

 539 See 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.”) 
Docket Nos. RM05-17-000 and RM05-25-000 - 513 - 

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 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 

 540 Citing Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ¶ 61,085, 

P 57 (2004) (applying Order 2003 crediting mechanism to network customers). 
Docket Nos. RM05-17-000 and RM05-25-000 - 514 - 

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 

 541 Comments 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 515 - 

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 

 542 Because 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 516 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 517 - 

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 

Report543 as well as provisions of EPAct 2005.544 We note that some RTOs and ISOs 

 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. 

544 Section 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 518 - 

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 as other nongeneration 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 

 

facilitated, and unnecessary barriers to demand response participation in energy, capacity 

and ancillary service markets shall be eliminated.” 
Docket Nos. RM05-17-000 and RM05-25-000 - 519 - 

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 costeffective 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 generation-related 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 520 - 

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 

 545 We 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 521 - 

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 commenters546 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 

 546 E.g., SPP, Alcoa, and Occidental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 522 - 

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 service, 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 out of AEP Serv. Corp.

548 SPP contends that the Commission can 

reduce uncertainty and litigation surrounding the pricing of reactive power by acting 

 547 See Order No. 2003-A at P 416. 

548 Opinion No. 440, 88 FERC ¶ 61,141 (1999). 
Docket Nos. RM05-17-000 and RM05-25-000 - 523 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 524 - 

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 noncomparable 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 

 549 See Order No. 2003-B at P 119. 

550 See Calpine Oneta Power, L.P.,116 FERC ¶ 61,282 (2006). 
Docket Nos. RM05-17-000 and RM05-25-000 - 525 - 

February 2005 report, Principles for Efficient and Reliable Reactive Power Supply and 

Consumption,551 as well as the above-cited 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 

 551 See 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 526 - 

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 

 553 See pro forma OATT section 13.5. 

554 See pro forma OATT section 19.3. 
Docket Nos. RM05-17-000 and RM05-25-000 - 527 - 

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 pointto-point service.556 The Commission proposed to modify the existing planning redispatch 

option by (1) accelerating the study of planning 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 

 555 See pro forma OATT sections 33.2-33.3. 

556 Conditional 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. 

557 The Commission did not propose to modify the reliability redispatch provisions 

that exist in the network integration transmission sections of the pro forma OATT. 
Docket Nos. RM05-17-000 and RM05-25-000 - 528 - 

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

 558 The 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. 

559 Questions relating to the TDA proposal are discussed later in this section. 
Docket Nos. RM05-17-000 and RM05-25-000 - 529 - 

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 point-topoint 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 

 560 E.g., Exelon, FirstEnergy, ELCON, MidAmerican, Arkansas Commission, 

MISO, and East Texas Cooperatives. 

561 E.g., EEI, Indianapolis Power, Ameren, and Northwest IOUs. 
Docket Nos. RM05-17-000 and RM05-25-000 - 530 - 

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

 562 E.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. 

563 E.g., California Commission Supplemental, Williams Supplemental, 

Constellation Supplemental, and Barrick Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 531 - 

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 long-term 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 

 564 E.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. 

565 E.g., Duke, EEI, LPPC, NRECA, NPPD, Progress Energy, Southern, Utah 

Municipals Reply, and Duke Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 532 - 

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 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 

 566 E.g., CREPC, TVA, and East Texas Cooperatives. 

567 E.g., EEI, Entergy, Ameren, Progress Energy, Santee Cooper, TAPS, E.ON 

Supplemental, TDU Systems Supplemental, LPPC Supplemental, Tacoma Supplemental, 

and PNM-TNMP Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 533 - 

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 

 568 E.g., Manitoba Hydro, Nevada Companies, Sacramento, Pinnacle, East Texas 

Cooperatives, Barrick Reply, APPA Supplemental, Community Power Alliance 

Supplemental, Entergy Supplemental, and TAPS Supplemental. 

569 Section V.D.1.b contains a summary and in-depth discussion of the TDA 

proposal. 

570 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 534 - 

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 

 571 E.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. 

572 E.g., California Commission, PGP, Pinnacle, and Imperial. 
Docket Nos. RM05-17-000 and RM05-25-000 - 535 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 536 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 537 - 

transmission providers offer to provide planning redispatch under certain circumstances 

in which the transmission providers determine that there is insufficient ATC. If 

customers 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 

 573 Application 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 538 - 

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 open-ended 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 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.575 

 574 As 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. 

575 The Commission did not propose to modify the reliability redispatch provisions 

that exist in the network integration transmission sections of the pro forma OATT. 
Docket Nos. RM05-17-000 and RM05-25-000 - 539 - 

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 

 576 E.g., EEI, TDU Systems, NRECA, Southern, and Duke Reply. 

577 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 540 - 

undeliverable.578 Entergy disagrees that there is undue discrimination because this 

service is not available to point-to-point customers, stating that network and point-topoint 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 

 578 Southern states that it offered this service on a comparable basis to a nonaffiliated transmission customer. 

579 E.g., TDU Systems and EEI Reply. 

580 E.g., LPPC, NPPD, Progress Energy, and Salt River. 
Docket Nos. RM05-17-000 and RM05-25-000 - 541 - 

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 long-term transmission service request 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-to-point 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 

 581 E.g., AWEA, Utah Municipals, Project for Sustainable FERC Energy Policy, 

EPSA, and Barrick Reply citing NOPR at P 300. 

582 EPSA Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 542 - 

service. 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 under-investment, 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 for 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 point-to-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. 

 583 E.g., EPSA, AWEA, and Project for Sustainable FERC Energy Policy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 543 - 

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 

point-to-point service.585

 584 See pro forma OATT section 19.3. 

585 See pro forma OATT section 13.5. 
Docket Nos. RM05-17-000 and RM05-25-000 - 544 - 

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 

 586 Entergy 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. 

587 SPS, 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 545 - 

support our finding that transmission providers currently evaluate transmission 

availability to serve long-term 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-to-point 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 

long-term 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 non-firm service for the 

 

Coordinator Readiness Audit Report Southern Subregion Reliability Coordinator, 19 

(March 27–30, 2006). 
Docket Nos. RM05-17-000 and RM05-25-000 - 546 - 

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 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 547 - 

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 long-term 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 548 - 

relative priorities applicable to firm point-to-point 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 point-to-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 

short-term 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. 

 588 See supra section V.D.5.b. 
Docket Nos. RM05-17-000 and RM05-25-000 - 549 - 

(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 

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 

 589 E.g., Duke, Entergy, WAPA, NRECA, NPPD, LPPC, and Southern. 

590 E.g., EEI, Indianapolis Power, Public Power Council, Southern, Seattle, 

Sacramento, and LPPC. 
Docket Nos. RM05-17-000 and RM05-25-000 - 550 - 

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 pointto-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-to-point 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 longterm 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 long-term 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 551 - 

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 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. 

 591 E.g., Duke, Entergy, Imperial, International Transmission, Salt River, Seattle, 

Southern, Tacoma, Northwest IOUs, Sacramento, Progress Energy, E.ON, Xcel, TVA, 

and EEI Reply. 

592 E.g., Sacramento and TVA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 552 - 

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. 

 593 E.g., Progress Energy, E.ON, WAPA, Entergy, and MidAmerican. 

594 E.g., Bonneville, Seattle, Public Power Council, and WAPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 553 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 554 - 

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 long-term contracts for 

firm power but may lead to a greater volume of short-term trading. 

 595 E.g., Ameren, Southern, and EEI. 
Docket Nos. RM05-17-000 and RM05-25-000 - 555 - 

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 long-term 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 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. 

 596 A 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 point-to-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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 556 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 557 - 

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 

 597 See, 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 558 - 

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. 

 598 E.g., Entergy. 

599 See also Order No. 888 at 31,739. 
Docket Nos. RM05-17-000 and RM05-25-000 - 559 - 

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 hydro-based 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 560 - 

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 hydro-based systems will focus on provision of 

the conditional firm option in a manner consistent with their system conditions. 

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 

 600 E.g., EEI, Duke, Imperial, LPPC, PNM-TNMP, Public Power Council, 

NRECA, NPPD, Southern, and Progress Energy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 561 - 

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-to-point 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 

 601 E.g., EEI, TAPS, LDWP, MidAmerican, Southern, Community Power 

Alliance, and MISO Reply. 

602 E.g., Duke, LPPC, NRECA, NPPD, Progress Energy, Southern, APPA, and 

South Carolina E&G. 
Docket Nos. RM05-17-000 and RM05-25-000 - 562 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 563 - 

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-to-point 

transmission service request. As described below, long-term point-to-point 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-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 564 - 

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 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. 

 603 Although 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 565 - 

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 ten-year 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 

 604 For 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 566 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 567 - 

(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 

 605 E.g., Progress Energy Supplemental, PNM-TNMP Supplemental, LPPC 

Supplemental, APPA Supplemental, TAPS Supplemental, TDU Systems Supplemental, 

NRECA Supplemental, EEI Supplemental, Entergy Supplemental, Ameren 

Supplemental, Powerex Supplemental, and MISO Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 568 - 

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 

non-bridge 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. 

 606 E.g., Bonneville Supplemental, PPL Supplemental, EPSA and AWEA 

Supplemental, EEI Supplemental, Barrick Supplemental, and Constellation 

Supplemental. 

607 E.g., Xcel Supplemental, Duke Supplemental, and EEI Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 569 - 

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 

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 

 608 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 570 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 571 - 

presents problems in offering longer-term 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 

 609 EPSA and AWEA endorse Constellation’s approach in defining and delineating 

the two forms of conditional firm service. 
Docket Nos. RM05-17-000 and RM05-25-000 - 572 - 

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 costcausation 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 short-term 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 

 610 E.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. 

612 E.g., Xcel Supplemental, Constellation Supplemental, and NRECA 

Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 573 - 

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 

 613 In the November 15 Notice, the Commission described an example of lumpy 

capacity as upgrades to provide a requested 100 MW of point-to-point service that results 

in 1,000 MW of additional transmission capacity. 

614 E.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 PNM-TNMP Supplemental. 

615 E.g., LPPC Supplemental, Bonneville Supplemental, and EEI Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 574 - 

be resolved on a bilateral contractual basis. Powerex suggests using an “open season” 

process to finance expensive and lumpy upgrades. California Commission supports pro 

rating large lumpy upgrades over a large base of new customers, to the extent that it is 

non-discriminatory 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 

long-term 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 575 - 

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 point-to-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 

 616 E.g., Xcel, PPM, and BP Energy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 576 - 

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 

 617 E.g., EEI, Southern, TVA, SPP, E.ON, and MISO. 

618 E.g., APPA, PNM-TNMP, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 577 - 

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 point-to-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 
Docket Nos. RM05-17-000 and RM05-25-000 - 578 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 579 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 580 - 

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 long-term 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 581 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 582 - 

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 

 619 See pro forma OATT section 19.3. 
Docket Nos. RM05-17-000 and RM05-25-000 - 583 - 

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 

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 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 584 - 

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-to-point 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 585 - 

(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. 

 621 E.g., MISO, PJM, California Commission, and ISO New England. 

622 E.g., AWEA, Indianapolis Power Reply, and Exelon Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 586 - 

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 longterm 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 

 623 Citing Attachment AC of the SPP OATT (Optimal Reservation Processing 

Method for Short Term Firm Transmission Services). 
Docket Nos. RM05-17-000 and RM05-25-000 - 587 - 

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 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 

 624 This includes the transmission provider’s obligation to post monthly redispatch 

costs for each transmission facility over which planning and reliability redispatch are 

provided. 
Docket Nos. RM05-17-000 and RM05-25-000 - 588 - 

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 

 625 E.g., Ameren, PNM-TNMP, Xcel, and WAPA. 

626 E.g., Southern, FirstEnergy, MidAmerican, and Community Power Alliance. 
Docket Nos. RM05-17-000 and RM05-25-000 - 589 - 

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 

 627 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 590 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 591 - 

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 off-system 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 

off-system redispatch, stating that lack of control over these resources could cause 

reliability problems on the originating transmission system. WAPA also believes that 

 628 E.g., Xcel, PNM-TNMP, and Public Power Council Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 592 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 593 - 

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 

 629 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 594 - 

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 providers 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 

 630 Network customers will continue, however, to be obligated to make their 

network resources available to the transmission provider for reliability redispatch in real 

time. 
Docket Nos. RM05-17-000 and RM05-25-000 - 595 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 596 - 

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 thirdparty resource fails to perform its contractual redispatch obligation. This or any other 

remedy for non-performance 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. 

(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 
Docket Nos. RM05-17-000 and RM05-25-000 - 597 - 

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 

 631 E.g., Powerex, Manitoba Hydro, Seattle, NRECA, Ameren, and E.ON. 
Docket Nos. RM05-17-000 and RM05-25-000 - 598 - 

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 near-term 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 

 632 E.g., Utah Municipals, Public Power Council, PPM, Entegra, Constellation, 

TransAlta and TAPS. 

633 American Electric Power Service Corp, 64 FERC ¶ 61,279 (1993) (American 

Electric Power). 
Docket Nos. RM05-17-000 and RM05-25-000 - 599 - 

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 an 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 

 634 Id. at 62,976. 
Docket Nos. RM05-17-000 and RM05-25-000 - 600 - 

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 

 635 E.g., Southern, MidAmerican, Entergy, FirstEnergy, Ameren, Nevada 

Companies, E.ON, and South Carolina E&G. 

636 E.g., EEI, Entergy, LPPC, NRECA, MidAmerican, Ameren, and FirstEnergy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 601 - 

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 ramp-down 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 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 

 637 E.g., LDWP, EEI, Ameren, MidAmerican, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 602 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 603 - 

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 open-ended 
Docket Nos. RM05-17-000 and RM05-25-000 - 604 - 

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 

 638 See, e.g., Florida Power & Light Co., 70 FERC ¶ 61,158 at 61,484 (1995). 
Docket Nos. RM05-17-000 and RM05-25-000 - 605 - 

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 the peak season, shoulder 

 639 Id. at 61,483. 
Docket Nos. RM05-17-000 and RM05-25-000 - 606 - 

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 

 640 See Order No. 888 at 31,740. 
Docket Nos. RM05-17-000 and RM05-25-000 - 607 - 

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 stand-alone 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 

 641 See 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 wellsettled matter that the Commission will not authorize “and” pricing, i.e., embedded cost 

pricing plus opportunity (incremental) cost pricing.”). 

642 Order No. 888A at 30,267. 
Docket Nos. RM05-17-000 and RM05-25-000 - 608 - 

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 

 643 Florida Power & Light Co., 70 FERC ¶ 61,158 at 61,483 (1995). 
Docket Nos. RM05-17-000 and RM05-25-000 - 609 - 

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 

 644 E.g., Nevada Companies, Community Power Alliance, Progress Energy, 

LPPC, Southern, WAPA, and APPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 610 - 

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. 

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 

 645 E.g., E.ON, Ameren, and APPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 611 - 

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 

 646 18 CFR 358.5. 
Docket Nos. RM05-17-000 and RM05-25-000 - 612 - 

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 transmission-related 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 

 647 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 613 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 614 - 

(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 long-term 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 615 - 

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 methodology compared to many in the Eastern 

Interconnection using a flow-based 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 longterm 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 

 648 E.g., LPPC Supplemental, PPL Supplemental, Williams Supplemental, 

Community Power Alliance Supplemental, Entergy Supplemental, and Southern 

Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 616 - 

defined system conditions or defined number of hours. We reject EEI’s suggestion to use 

a monthly non-firm 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 

 649 Potential New Wholesale Transmission Services, Notice of Final Agenda for 

Technical Workshop, 70 FR 12865 (Mar. 16, 2005). 

650 E.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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 617 - 

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 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 618 - 

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 non-public 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 619 - 

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 possible system conditions required to estimate 

the conditional curtailment hours would be complex, time-consuming 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 

 652 E.g., Imperial, Duke, Progress Energy, MidAmerican, PNM-TNMP, Southern, 

and EEI. 
Docket Nos. RM05-17-000 and RM05-25-000 - 620 - 

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 

 653 E.g., Barrick Supplemental, Bonneville Supplemental, BP Energy 

Supplemental, and EPSA and AWEA Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 621 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 622 - 

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. 

 654 E.g., AWEA, EPSA, Project for Sustainable FERC Energy Policy, Santee 

Cooper, Seattle, Entergy, and LPPC. 

655 E.g., Santee Cooper, Seattle, Entergy, LPPC, and Nevada Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 623 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 624 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 625 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 626 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 627 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 628 - 

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 nonfirm 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 

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 

 656 E.g., Bonneville, AWEA Reply, and EPSA Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 629 - 

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 realtime redispatch options and contradict Order No. 888 precedent that provides priority 

non-firm 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 longterm 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-to-point customers pay for service on a long-term basis but, unlike 

network customers, they do not get priority non-firm 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 

 657 Citing Order No. 888 at 31,750. 
Docket Nos. RM05-17-000 and RM05-25-000 - 630 - 

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 

 658 E.g., EEI, EPSA, TranServ, Bonneville, Constellation and Seattle Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 631 - 

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 nonconditional 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 long-term firm point-to-point rate and thus should receive the highest non-firm 
Docket Nos. RM05-17-000 and RM05-25-000 - 632 - 

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-to-point 

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 

 659 See pro forma OATT section 14.7. 
Docket Nos. RM05-17-000 and RM05-25-000 - 633 - 

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 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 non-firm 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 

 660 For 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 IRO006-3, Transmission Loading Relief Procedures – Eastern Interconnection, section 6.2 

(Communications and Timing Requirements) at 23-25 (August 2, 2006). 
Docket Nos. RM05-17-000 and RM05-25-000 - 634 - 

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 short-term 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 short-term 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 635 - 

(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 

 661 E.g., AWEA, EPSA, Manitoba Hydro, Bonneville, TranServ, Seattle, and Utah 

Municipals Reply. 

662 E.g., EEI, FirstEnergy, Ameren, SPP, and TDU Systems Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 636 - 

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 point-to-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 
Docket Nos. RM05-17-000 and RM05-25-000 - 637 - 

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-to-point 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 at least 30 days prior to the relevant rollover deadline. i 

1084. Additionally, because the biennial review provides the transmission provider with 

the ability to plan for and maintain system reliably, we will not allow the rollover right to 
Docket Nos. RM05-17-000 and RM05-25-000 - 638 - 

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 load-following service like network service. EEI 

asserts that because the Commission requires that network resources be deliverable on a 

 663 Such a review would occur in the first year of a rolled over service if the initial 

service term was for five years. 

664 E.g., Entergy Supplemental, Southern Supplemental, MISO Supplemental, 

Community Power Alliance Supplemental, and Powerex Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 639 - 

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. 

 665E.g., AWEA, EPSA, TAPS, APPA, Utah Municipals Reply, and Barrick Reply. 

666 E.g., Bonneville Supplemental, TDU Systems Supplemental, PPL 

Supplemental, and BP Energy Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 640 - 

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-to-point 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 

 667 E.g., NRECA, TDU Systems, TAPS, and Utah Municipals Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 641 - 

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 

 668 E.g., APPA Supplemental, EPSA and AWEA Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 642 - 

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 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 

 669 Wisconsin Public Power Inc. v. Wisconsin Public Service Corp., 84 FERC 

¶ 61,120 at 61,660 (1998) (WPPI).
Docket Nos. RM05-17-000 and RM05-25-000 - 643 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 644 - 

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 

 670 See section V.C.1 of this Final Rule for a discussion of comments regarding 

independent dispatch and spot market development. 
Docket Nos. RM05-17-000 and RM05-25-000 - 645 - 

(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 

 671 Transparent 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 646 - 

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’ real-time reliability redispatch obligations and incorporate third 

party bids into redispatch. As discussed in detail above, transmission providers will 
Docket Nos. RM05-17-000 and RM05-25-000 - 647 - 

continue to have an obligation to 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 648 - 

border of the transmission provider’s system.”672 Transparent Dispatch Advocates 

contend that the publication of this data would: allow customers to assess available realtime 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 

 672 Transparent Dispatch Advocates Reply at 5. 
Docket Nos. RM05-17-000 and RM05-25-000 - 649 - 

data concerning the response required to relieve congestion. Additionally, the TDA 

Summary states that the transmission provider would have no obligation to provide for 

real-time 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 650 - 

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 nonnetwork 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 

 673 E.g., EPSA and AWEA Supplemental, Constellation Supplemental, California 

Commission Supplemental, PPL Supplemental, BP Energy Supplemental, PPM, and San 

Diego G&E. 
Docket Nos. RM05-17-000 and RM05-25-000 - 651 - 

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. 

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 

 674 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 652 - 

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 

 675 E.g., Alabama Commission Supplemental, Florida Commission Supplemental, 

Georgia Commission Supplemental, North Carolina Commission Supplemental, South 

Carolina Regulatory Staff, and SEARUC Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 653 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 654 - 

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. 

 676 Commenters 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). 

677 E.g., Community Power Alliance Supplemental, and Entergy Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 655 - 

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 real-time 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 real-time 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 

 678 EPSA and AWEA Supplemental, BP Energy Supplemental, California 

Commission Supplemental, 

679 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 656 - 

transmission owners in non-RTO 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 

 680 E.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. 

681 E.g., Entergy Supplemental, LPPC Supplemental, Public Power Council 

Supplemental, and OG&E Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 657 - 

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 

 682 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 658 - 

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 market-based 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 market-based 

price for generation offered for redispatch service. LPPC, TDU Systems, TAPS, APPA 

and NRECA express concern about allowing redispatch providers to bid under marketbased 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, 

 683 E.g., Progress Energy and MidAmerican Supplemental, APPA Supplemental, 

NRECA Supplemental, and TAPS Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 659 - 

given the high concentration of transmission provider-owned 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 660 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 661 - 

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 providers’ 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. 

 684 E.g., LPPC Supplemental, TAPS Supplemental, NRECA Supplemental, 

Southern Supplemental, South Carolina E&G Supplemental, and E.ON Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 662 - 

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 

 685 E.g., Nevada Companies Supplemental, Community Power Alliance 

Supplemental, Southwest Utilities Supplemental, and Southern Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 663 - 

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 

 686 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 664 - 

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 thirdparty 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 665 - 

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. 

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 argue that it would appear that 

 687 E.g., Community Power Alliance Supplemental, Southwest Utilities 

Supplemental, Florida Commission Supplemental, Ameren Supplemental, and Entergy 

Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 666 - 

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 assert 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 

 688 E.g., APPA Supplemental, LPPC Supplemental, Community Power Alliance 

Supplemental, South Carolina E&G Supplemental, Progress Energy and MidAmerican 

Supplemental, and Southern Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 667 - 

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 resale 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 

ground that they are the functional equivalent of a jurisdictional service.690 LPPC also 

 689 Transparent Dispatch Advocates Reply at 17. 

690 Citing 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 668 - 

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 

 691 372 F.3d 395 (D.C. Cir. 2004). 
Docket Nos. RM05-17-000 and RM05-25-000 - 669 - 

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-to-point 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 

 692 Compare 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). 

693 Transparent Dispatch Advocates Reply at 18. 
Docket Nos. RM05-17-000 and RM05-25-000 - 670 - 

TDA Summary states that transmission providers would not be obligated to provide their 

resources for real-time redispatch, but the Transparent 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 realtime reliability redispatch obligation of transmission providers must be extended to “nonnetwork 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-topoint transmission customers amounts to undue discrimination. Order No. 888 provided 

for reliability redispatch for network customers but not for firm point-to-point 

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 

 694 See 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-to-point customers and no obligation for point-to-point customers to participate in 

reliability redispatch). 
Docket Nos. RM05-17-000 and RM05-25-000 - 671 - 

native load and network customers. There is no corresponding obligation on point-topoint 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-to-point 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 

 695 See, 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 point-to-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). 

696 Northern States Power, 83 FERC ¶ 61,338 at 62,369. 
Docket Nos. RM05-17-000 and RM05-25-000 - 672 - 

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 real-time 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 673 - 

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 

long-term 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 real-time marginal costs of electricity.”697 In reply 

comments, Transparent Dispatch Advocates request that the Commission require 

publication of “dynamic real-time 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 

 697 PJM at 6. 

698 Transparent Dispatch Advocates Reply at 5. 
Docket Nos. RM05-17-000 and RM05-25-000 - 674 - 

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 using system costs instead of unit-specific 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 

 699 Transparent Dispatch Advocates Supplemental at 7. 
Docket Nos. RM05-17-000 and RM05-25-000 - 675 - 

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” 

 700 E.g., EPSA and AWEA Supplemental, BP Energy Supplemental, and 

California Commission Supplemental. 

701 PGP asserts that the transmission provider should be required to post redispatch 

information by event and by entity to address concerns about anticompetitive behavior. 
Docket Nos. RM05-17-000 and RM05-25-000 - 676 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 677 - 

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 pre-established 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 678 - 

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 

 702 18 U.S.C. 1905. 
Docket Nos. RM05-17-000 and RM05-25-000 - 679 - 

buyers with commercially-sensitive information.703 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 resourcespecific 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. 

 703 E.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. 

704 E.g., Entergy Supplemental, Community Power Alliance Supplemental, 

Southern Supplemental, Duke Supplemental and South Carolina E&G Supplemental. 
Docket Nos. RM05-17-000 and RM05-25-000 - 680 - 

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)(l) 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 

 705 Entergy 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 681 - 

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. 

 706 Ameren 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? 
Docket Nos. RM05-17-000 and RM05-25-000 - 682 - 

1154. Duke believes that the posting of hourly redispatch costs would create nearconstant 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 683 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 684 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 685 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 686 - 

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 

 707 The 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. 

708 For 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 687 - 

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. 

 709 This 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 688 - 

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. 

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 

 710 E.g., MidAmerican, Public Power Council, Northwest IOUs, Xcel, Powerex 

Reply, PPL, and Seattle Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 689 - 

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 long-term 

point-to-point transmission service rate pro-rated 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-topoint service, but would allow the transmission customer to dynamically monitor its 
Docket Nos. RM05-17-000 and RM05-25-000 - 690 - 

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 point-to-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 pointto-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 
Docket Nos. RM05-17-000 and RM05-25-000 - 691 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 692 - 

inconsistent with the policy in the pro forma OATT that values firm service over nonfirm 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 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 

 711 Order No. 888-A at 30,235-36. 
Docket Nos. RM05-17-000 and RM05-25-000 - 693 - 

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 

 712 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 694 - 

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 seeks 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 695 - 

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 10:00 

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 

 713 See 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 non-firm 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 696 - 

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 

 714 E.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. 

715 E.g., Bonneville, Pinnacle (noting Arizona Public Service Company’s adoption 

of the service), PNM-TNMP, and WAPA (in its Desert-Southwest region) 
Docket Nos. RM05-17-000 and RM05-25-000 - 697 - 

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 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 

 716 E.g., Arkansas Commission, BP Energy, FirstEnergy, Morgan Stanley, 

Pinnacle, PNM-TNMP, and PPL. 

717 E.g., APPA, Duke, EEI, MISO, and Southern. 

718 E.g., MISO and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 698 - 

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 

 719 E.g., APPA, NRECA, and Southern. 

720 E.g., Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 699 - 

for each hour of a given day. If system conditions then change, Southern continues, 

reliability could be placed in jeopardy, which would result in long-term 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 

 721 E.g., LDWP, MISO, Southern, TAPS, TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 700 - 

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 10:00 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 

 722 E.g., ELCON, FirstEnergy, Powerex, and South Carolina E&G. 
Docket Nos. RM05-17-000 and RM05-25-000 - 701 - 

transmission providers will enforce the 10:00 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 

 723 E.g., APPA, NRECA, Southern, and TAPS 

724 E.g., APPA, Duke, East Texas Cooperatives, EEI, Imperial, LDWP, LPPC, 

Northwest IOUs, NRECA, PJM, Southern, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 702 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 703 - 

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 non-firm 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 704 - 

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. 

 725 E.g., Ameren, EEI, NorthWestern, PGP, and PNM-TNMP. 

726 E.g., Northwest IOUs, Public Power Council, and CREPC. 

727 E.g., Ameren, Duke, NorthWestern, PNM-TNMP, and WAPA. 

728 E.g., Bonneville, Southern, and TVA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 705 - 

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 10:00 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 10:00 a.m. on the day prior all 

the way up until one hour before the service is to commence. TVA argues that no service 

 729 E.g., Public Power Council and Tacoma. 
Docket Nos. RM05-17-000 and RM05-25-000 - 706 - 

that could preempt the hourly service should be sold after the 10:00 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 day-ahead 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 

Bonneville’s scheduling timeline as an example in which longer blocks get priority over 

 730 E.g., MidAmerican, Northwest IOUs, Public Power Council, and CREPC. 
Docket Nos. RM05-17-000 and RM05-25-000 - 707 - 

the shorter blocks within the 10:00 a.m. to 2:00 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 10:00 a.m. day-before 

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 10:00 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 2:00 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 708 - 

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 10:00 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 709 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 710 - 

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 Commission-approved 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 

 731 E.g., PGP, PNM-TNMP, and WAPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 711 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 712 - 

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 short-term 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 713 - 

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 

 732 Order No. 888 at 31,665 n.176. 
Docket Nos. RM05-17-000 and RM05-25-000 - 714 - 

load use.733 The Commission also has held that a transmission provider may restrict a 

right of first refusal based on pre-existing 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 long-term 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 

 733 Id. at 31,694. 

734 E.g., Southwest Power Pool, Inc., 109 FERC ¶ 61,041 at P 6 (2004). 

735 Id. at P 9. 
Docket Nos. RM05-17-000 and RM05-25-000 - 715 - 

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 existing 

transmission customer match competing offers as to term and rate. The Commission 

 736 Id.

737 Idaho Power Co. v. FERC, 312 F.3d 454, 462 (D.C. Cir. 2002). 
Docket Nos. RM05-17-000 and RM05-25-000 - 716 - 

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 

 738 E.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, PNMTNMP, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 717 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 718 - 

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 longterm 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 

 739 See also TDU Systems Reply. 

740 See also NCEMC and Arkansas Municipal (opposing the increase in the 

minimum term to five years). 
Docket Nos. RM05-17-000 and RM05-25-000 - 719 - 

matching exposure for small embedded transmission-dependent utilities and full or nearfull 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, believe 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’ 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 720 - 

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’ 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 aggregated loads of several 

small customers can have a substantial impact on the system. EEI contends that TAPS’ 

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

 741 In their replies, Entergy, MidAmerican, and Progress Energy note many of 

these same concerns. 
Docket Nos. RM05-17-000 and RM05-25-000 - 721 - 

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 

five-year 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. 

 742 E.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. 

743 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 722 - 

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 two to 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 

 744 E.g., EPSA, Exelon, Reliant, and MISO/PJM States. 

745 E.g., EEI Reply and Southern Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 723 - 

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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 724 - 

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 

 746 E.g., Morgan Stanley and Manitoba Hydro.

747 E.g., Alberta Intervenors, TransAlta, and Williams. 
Docket Nos. RM05-17-000 and RM05-25-000 - 725 - 

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 deeppocketed market participants who can afford long 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 

 748 See also Morgan Stanley. 
Docket Nos. RM05-17-000 and RM05-25-000 - 726 - 

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 longerterm 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 five-year 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 

 749 See 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.” 
Docket Nos. RM05-17-000 and RM05-25-000 - 727 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 728 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 729 - 

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 

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 

 750 We 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 730 - 

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 oneyear 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 731 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 732 - 

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 

 751 E.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, PNMTNMP, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 733 - 

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 one-year notice period does not 

ensure that the transmission provider will be able to re-market the capacity, forcing other 

transmission customers to bear the increased costs associated with the newly constructed 

 752 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 734 - 

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 one-year notice without a link to 

the start date for any upgrades falls short of the native load protections found in section 

 753 Ameren, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 735 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 736 - 

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 short-term firm or nonfirm 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. 

 754 E.g., Alberta Intervenors, Alcoa, Arkansas Municipal, EPSA, Exelon, Manitoba 

Hydro, Morgan Stanley, PPM, TransAlta, Williams, and Wisconsin Electric. 

755 E.g., Arkansas Municipal, Williams, and Wisconsin Electric. 
Docket Nos. RM05-17-000 and RM05-25-000 - 737 - 

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 long-term 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 738 - 

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 three-to-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 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 

 756 E.g., MidAmerican and Powerex. 
Docket Nos. RM05-17-000 and RM05-25-000 - 739 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 740 - 

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 investor-owned 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 

 757 E.g., Allegheny, Entergy, FirstEnergy, Imperial, Nevada Companies, Progress 

Energy, Salt River, Santa Clara, and Seattle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 741 - 

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 

 758 E.g., AWEA, Duke, EEI, Entergy, EPSA, Imperial, Nevada Commission, 

Powerex, Salt River, Seattle, South Carolina E&G, Southern, SPP Reply, and TAPS. 

759 E.g., AWEA, EEI, EPSA, and MISO. 
Docket Nos. RM05-17-000 and RM05-25-000 - 742 - 

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 higher-queued 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 

 760 E.g., Nevada Companies, South Carolina E&G, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 743 - 

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 transmission-dependent utilities – the same, without 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 

 761 See also APPA Reply and TDU Systems Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 744 - 

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 

 762 See Order No. 888-A at 30,197. 

763 Id. 
Docket Nos. RM05-17-000 and RM05-25-000 - 745 - 

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 stateapproved 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 

 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). 

765 We 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 746 - 

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 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 747 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 748 - 

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 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 

 767 E.g., AWEA, Constellation, EPSA, Exelon, PGP, and PPM. 

768 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 749 - 

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 

 769 E.g., Northwest IOUs, Duke Reply and EEI Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 750 - 

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 

 770 E.g., APPA, FirstEnergy, Northwest IOUs, PGP, and Public Power Council. 
Docket Nos. RM05-17-000 and RM05-25-000 - 751 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 752 - 

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 Non-Firm 

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 non-firm 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 section 17 of the pro forma OATT (Procedures for Arranging Firm 

Point-to-Point 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 753 - 

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 

 771 The 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. 

772 The 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. 

773 The 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.
Docket Nos. RM05-17-000 and RM05-25-000 - 754 - 

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 

 774 Order No. 676 at P 52. 

775 Id. at P 53-61. 
Docket Nos. RM05-17-000 and RM05-25-000 - 755 - 

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 

 776 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 756 - 

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 

 777 E.g., EEI, Imperial, NorthWestern, Southern, and Suez Energy NA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 757 - 

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 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 

 778 E.g., EEI, NorthWestern, and Seattle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 758 - 

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 pointto-point 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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 759 - 

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 shortterm 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 

 779 See Standards for Business Practices of Interstate Natural Gas Pipelines, Order 

No. 587-N, FERC Stats. & Regs. ¶ 31,125 at P 23 (2002). 

780 See Order No. 676 at P 12. 
Docket Nos. RM05-17-000 and RM05-25-000 - 760 - 

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 

 781 TranServ explains that these are two primary features in a revised WEQ 001-

9.7 standard that was open for public comment. 
Docket Nos. RM05-17-000 and RM05-25-000 - 761 - 

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

 782 95 FERC ¶ 61,027 at 61,083 (2001). 

783 The 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 762 - 

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 long-term firm transmission 

service agreement.”785 Thus, there is no inconsistency between the Commission’s 

redirect policy and Order No. 676. 

 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 

 784 97 FERC ¶ 61,207 at 61,905-06 (2001). 

785 Id.
Docket Nos. RM05-17-000 and RM05-25-000 - 763 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 764 - 

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-to-point 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 765 - 

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 on-peak 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-to-point 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 

 786 Midwest Independent Transmission System Operator, Inc., 118 FERC ¶ 61,095 

at P 79-85(2007). 

787 See Appalachian Power Co., 39 FERC ¶ 61,296 (1987). 
Docket Nos. RM05-17-000 and RM05-25-000 - 766 - 

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 off-peak 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-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 767 - 

on properly scheduling for reliability increases exponentially when there are redirects of 

redirects. 

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 asavailable basis. 

1294. For similar reasons, the Commission denies Alberta Intervenors’ request. The 

Commission has explained that customers must choose between point-to-point and 
Docket Nos. RM05-17-000 and RM05-25-000 - 768 - 

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 

 788 Order No. 888-A at 30,260. 
Docket Nos. RM05-17-000 and RM05-25-000 - 769 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 770 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 771 - 

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 non-affiliates’ 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 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 

 789 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 772 - 

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. 

PNM-TNMP 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 773 - 

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. 

 790 E.g., CREPC, MISO, Constellation, and TDU Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 774 - 

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 

 791 372 F.3d 395, 404 (D.C. Cir. 2004). 
Docket Nos. RM05-17-000 and RM05-25-000 - 775 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 776 - 

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. 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 long-term 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 777 - 

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-topoint 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 

o Number of new system impact study agreements delivered to 

transmission customers

o Number of new system impact study agreements delivered to the 

transmission customer more than 30 days after the transmission 

customer submitted its request

o Average time (days) from request submittal to change in request status 

o Average time (days) from request submittal to delivery of system 

impact study agreement 

o 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 

o Number of system impact studies completed 

o Number of system impact studies completed more than 60 days after 

receipt of executed system impact study agreement 

o Average time (days) from receipt of executed system impact study 

agreement to date when completed system impact study made available 

to the transmission customer 

o Average cost of system impact studies completed during the period 

• Service requests withdrawn from system impact study queue 

o Number of requests withdrawn from the system impact study queue 

o Number of system impact studies withdrawn more than 60 days after 

receipt of executed system impact study agreement 

o Average time (days) from receipt of executed system impact study 

agreement to date when request was withdrawn from the system impact 

study queue 
Docket Nos. RM05-17-000 and RM05-25-000 - 778 - 

• 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 

o Number of new facilities study agreements delivered to transmission 

customers 

o Number of new facilities study agreements delivered to transmission 

customers more than 30 days after the completion of the system impact 

study 

o Average time (days) from completion of system impact study to 

delivery of facilities study agreement 

o Number of new facilities study agreements executed 

• Facilities study processing time pursuant to sections 19.4 and 32.4 

o Number of facilities studies completed 

o Number of facilities studies completed more than 60 days after receipt 

of executed facilities study agreement 

o Average time (days) from receipt of executed facilities study agreement 

to date when completed facilities study made available to the 

transmission customer 

o Average cost of facilities studies completed during the period 

o Average cost of recommended upgrades for facilities studies completed 

during the period 

• Service requests withdrawn from facilities study queue 

o Number of requests withdrawn from the facilities study queue 

o Number of facilities studies withdrawn more than 60 days after receipt 

of executed facilities study agreement 

o 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 779 - 

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, 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 

 792 The 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 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 780 - 

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 

 793 18 CFR 37.7(b). 
Docket Nos. RM05-17-000 and RM05-25-000 - 781 - 

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. 

 794 E.g., Constellation, EPSA NOI Comments, Arkansas Cities NOI Comments, 

APPA NOI Reply Comments, and Powerex NOI Reply Comments 
Docket Nos. RM05-17-000 and RM05-25-000 - 782 - 

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 time frame 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 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 783 - 

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 non-discriminatory 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 

 796 18 CFR 37.6(b)(2)(iii). 
Docket Nos. RM05-17-000 and RM05-25-000 - 784 - 

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 time frame. 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 time frame, provide 

an expected completion date, and explain why additional time is needed. We do 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 non-affiliates’ 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 785 - 

transmission provider processes more than 20 percent of non-affiliates’ 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 nonaffiliates.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 employeehours 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 non-affiliates’ requests for 

transmission service and for short-term and long-term transmission service. The 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 786 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 787 - 

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 

 798 E.g., Constellation, EPSA NOI Comments, Arkansas Cities NOI Comments, 

APPA NOI Reply Comments, and Powerex NOI Reply Comments 
Docket Nos. RM05-17-000 and RM05-25-000 - 788 - 

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 would be 

subject to an operational penalty if it continues to be out of compliance799 with the 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 789 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 790 - 

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 

 800 E.g., EEI, MidAmerican, Entergy, Southern, Imperial, NorthWestern, PNMTNMP, Salt River, and Bonneville Reply. 

801 E.g., EEI, Southern, and PNM-TNMP Reply. 

802 E.g., MidAmerican, Southern, Imperial, and EEI Reply. 

803 E.g., MidAmerican, Southern, NorthWestern, Northwest IOUs, and PNMTNMP Reply. 

804 E.g., MidAmerican, Southern, and EEI Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 791 - 

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 

 805 E.g., EEI, Southern, Northwest IOUs, and MidAmerican. 

806 E.g., EEI and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 792 - 

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 

 807 E.g., Suez Energy NA, TAPS, Constellation, Entegra, TDU Systems, CREPC, 

and Nevada Companies. 
Docket Nos. RM05-17-000 and RM05-25-000 - 793 - 

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. 

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, 

 808 E.g., TAPS, Constellation, and Entegra. 
Docket Nos. RM05-17-000 and RM05-25-000 - 794 - 

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.

 809 E.g., Bonneville, MidAmerican, Progress Energy, NorthWestern, Northwest 

IOUs, and EEI Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 795 - 

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 Commission-approved 

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 

 810 E.g., MISO, MISO/PJM States, TDU Systems, and Indianapolis Power Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 796 - 

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. 

 811 E.g., Southern, TAPS, Progress Energy, Salt River, and Xcel. 
Docket Nos. RM05-17-000 and RM05-25-000 - 797 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 798 - 

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 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. 

 812 E.g., Duke, MidAmerican, and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 799 - 

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 non-compliance. The transmission provider 

will be deemed to be out of compliance if it completes 10 percent or more of nonaffiliates’ 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 800 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 801 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 802 - 

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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 803 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 804 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 805 - 

persistently fails to adhere to the relevant timelines. Rather, we will review each such 

instance on a case-by-case 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 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
Docket Nos. RM05-17-000 and RM05-25-000 - 806 - 

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. 

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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 807 - 

absent concrete evidence to the contrary, that the existing time frame 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.1of 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 time frame 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 808 - 

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. 

 813 Rules 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.”). 
Docket Nos. RM05-17-000 and RM05-25-000 - 809 - 

(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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 810 - 

(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 

 814 E.g., MidAmerican, MISO, Seattle, Southern, TranServ, TAPS, and CREPC. 
Docket Nos. RM05-17-000 and RM05-25-000 - 811 - 

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 self-competing. TranServ suggests that the fee apply to requests for longterm 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 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 newly-adopted 

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 

 815 E.g., EEI, Nevada Companies, Powerex, and Suez Energy NA. 

816 E.g., EEI, Powerex, Suez Energy NA, and Entegra. 
Docket Nos. RM05-17-000 and RM05-25-000 - 812 - 

should focus on narrowly-tailored 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, 

 817 E.g., EEI and TAPS. 

818 See Midwest Independent Transmission System Operator, Inc., 97 FERC ¶ 61,269 

(2001) (rejecting a proposal to include a fee for non-confirmed transmission service 

requests for firm point-to-point transmission service of one week or longer). 
Docket Nos. RM05-17-000 and RM05-25-000 - 813 - 

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 end-run 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 

multi-system 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 814 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 815 - 

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” 

 819 E.g., CREPC, Powerex, and Suez Energy NA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 816 - 

study clusters. If transmission providers are required to study requests in a group, 

Powerex believes customers should be 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 

 820 E.g., Bonneville, EEI, MISO, Nevada Companies, Southern, Entegra, and PNMTNMP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 817 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 818 - 

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 

 821 E.g., NRECA, TDU Systems, and Seattle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 819 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 820 - 

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. 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 821 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 822 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 823 - 

(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 shortterm firm and non-firm point-to-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 

point-to-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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 824 - 

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 proposal on granting 
Docket Nos. RM05-17-000 and RM05-25-000 - 825 - 

priority to pre-confirmed 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-to-point 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 

 822 See, e.g., Florida Power Corp., 111 FERC ¶ 61,243 at P 5 (2005). 
Docket Nos. RM05-17-000 and RM05-25-000 - 826 - 

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 

 823 18 CFR 37.6(g)(4). 
Docket Nos. RM05-17-000 and RM05-25-000 - 827 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 828 - 

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 point-to-point service on 

a first-come, first-served 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 829 - 

(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 short-term request for firm 

transmission service would preempt any non-pre-confirmed short-term requests, 

regardless of duration. Similarly, the Commission proposed that a pre-confirmed 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 pre-empt a non-preconfirmed request for long-term transmission service. 

Comments 

1396. A number of commenters generally support the Commission’s proposal to give 

priority to pre-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 

 824 E.g., Nevada Companies, Seattle, LDWP, PGP, PNM-TNMP, Salt River, and 

Suez Energy NA. 

825 E.g., Ameren, Santa Clara, Entegra, Entergy, and TVA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 830 - 

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 non-refundable 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 

pre-confirmation as a tie-breaker for short-term 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 pre-confirmed. 

 826 E.g., Ameren and NorthWestern. 

827 E.g., CREPC and EEI. 

828 E.g., Entergy, Southern, and NorthWestern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 831 - 

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 

pre-confirmed request for transmission service while it is actively studying a request for 

service that has not been pre-confirmed. 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, 

 829 E.g., Bonneville and EEI. 

830 E.g., Bonneville, EEI, and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 832 - 

Southern believes that a pre-confirmed service request submitted within close proximity 

to the actual commencement of service should not preempt an existing non-preconfirmed 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 

 831 E.g., EEI, MISO, TAPS, Constellation, and TDU Systems. 

832 Open 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). 

833 E.g., MidAmerican and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 833 - 

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 longer-term uses of the 

transmission system, disrupt the study process, or disadvantage transmission customers 

that are not in the position to pre-confirm 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-to-point transmission service 

requests. In addition, longer duration requests for transmission service will continue to 

have priority over shorter duration requests for transmission service, with preconfirmation 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 pre-confirmed 

requests thus addresses the comments that we should preserve the priority of longer 

duration requests for transmission service over shorter duration requests for transmission 
Docket Nos. RM05-17-000 and RM05-25-000 - 834 - 

service. For instance, a pre-confirmed daily or hourly request will not preempt a weekly 

request that has not been pre-confirmed. Pre-confirmed short-term service requests 

therefore will not have a priority superior to that of long-term service requests that have 

not been pre-confirmed. 

1402. We acknowledge that our revised policy on priority for pre-confirmed 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 hoarding834 – 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 preconfirmed request for transmission service at any time prior to acceptance by a 

transmission provider. We believe prohibiting withdrawal of a pre-confirmed request is 

less administratively burdensome than the non-refundable deposit on requests proposed 

 834 See Order No. 676 at P 19 
Docket Nos. RM05-17-000 and RM05-25-000 - 835 - 

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 preconfirmed 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 pre-confirmed 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 pre-empt 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 836 - 

Handling priority for pre-confirmed 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 pre-confirm 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 pre-confirmed 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’ 
Docket Nos. RM05-17-000 and RM05-25-000 - 837 - 

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 preconfirmed 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 pre-confirmed 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. 

 835 See Order No. 676. 
Docket Nos. RM05-17-000 and RM05-25-000 - 838 - 

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 tie-breaker 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. 

 836 E.g., EEI and MidAmerican. 
Docket Nos. RM05-17-000 and RM05-25-000 - 839 - 

638, we clarify that, in the event a later queued short-term request for 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 tiebreaker 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-to-point transmission service on the secondary market 

 837 See Order No. 638 at 31,442.
Docket Nos. RM05-17-000 and RM05-25-000 - 840 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 841 - 

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 anti-competitive behavior. A number of commenters also 

suggest that such a system should be limited to short-term transmission service841 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 five-minute window policy, then the policy should not be 

 838 E.g., Bonneville and Santa Clara. 

839 E.g., TDU Systems and NRECA. 

840 E.g., Bonneville and CREPC. 

841 E.g., Bonneville and Nevada Companies. 

842 E.g., Bonneville and NRECA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 842 - 

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. 

 843 E.g., EEI, MidAmerican, Ameren, Constellation, Entergy, NorthWestern, 

PNM-TNMP, WAPA, Powerex, and Indianapolis Power Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 843 - 

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 as a tiebreaker for simultaneous requests could discriminate against purchased power contracts 

that are designated as network resources. 

 844 E.g., Powerex and TranServ. 

845 Id.
Docket Nos. RM05-17-000 and RM05-25-000 - 844 - 

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, first-served 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 845 - 

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 can not be meaningfully differentiated. A transmission provider with 

such a business practice or tariff provision will be required to modify its tariff to include 

 846 See NAESB Business Practice Standard 001-4.13. 

847 For instance, Idaho Power Company has adopted a business practice that 

requests for monthly firm transmission service can not be submitted earlier than 11 

months prior to operation. Portland General Electric has adopted a business practice that 

Daily Firm ATC on the California-Oregon 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 can not be submitted more than 90 days prior to the first day of 

operation. 
Docket Nos. RM05-17-000 and RM05-25-000 - 846 - 

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 can not 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 847 - 

(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 shortterm 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 848 - 

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 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 point-to-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 
Docket Nos. RM05-17-000 and RM05-25-000 - 849 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 850 - 

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 shorter term 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 851 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 852 - 

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 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

 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). 

849 Wisconsin Public Power Inc. v. Wisconsin Public Service Corp., 84 FERC 

¶ 61,120 at 61,650-51 (1998) (WPPI).

850 Id.

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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 853 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 854 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 855 - 

(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 

 853 E.g., Ameren, BART, Constellation, Duke, Entegra, Entergy, Morgan Stanley, 

MISO, NorthWestern, Progress Energy, Sempra Global, Southern, Suez Energy NA, and 

TranServ. 

854 E.g., AMP-Ohio, APPA, Duke, EEI, Entergy, Fayetteville, Morgan Stanley, 

NCPA, Northwest IOUs, Northwest Parties, MISO/PJM States, PGP, Pinnacle, PNMTNMP, Salt River, Sempra Global, Southern, TAPS, Utah Municipals, and WSPP. 

855 E.g., AMP-Ohio, Northwest IOUs, NRECA Reply, PGP, Pinnacle, Sempra 

Global, Strategic Energy Reply, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 856 - 

finding in Dynegy856 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 

 856 Dynegy Midwest Generation, 101 FERC ¶ 61,295 (2002), reh’g dismissed, 

108 FERC ¶ 61,175 (2004) (Dynegy). 

857 E.g., Duke, Dynegy Reply, EEI, and Southern. 

858 Dynegy at P 21. 

859 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 857 - 

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 non-performing 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 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. 

 860 E.g., Hoosier Reply, Strategic Energy Reply, and Utah Municipals. 
Docket Nos. RM05-17-000 and RM05-25-000 - 858 - 

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. 

 861 E.g., APPA, Hoosier Reply, NCPA, Southern, Strategic Energy Reply, and 

Utah Municipals. 

862 E.g., EEI, Hoosier Reply, Southern and NCPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 859 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 860 - 

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 

 863 MISO/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. 

864 E.g., APPA Reply, Morgan Stanley, and NCPA. 

865 E.g., Duke, Dynegy, and Detroit EdisonReply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 861 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 862 - 

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 

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 

 866 E.g., APPA, EEI, Entergy, Northwest Parties, Salt River, Utah Municipals, and 

WSPP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 863 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 864 - 

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 WPPI867 (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. 

 867 WPPI, 84 FERC at 61,652. 
Docket Nos. RM05-17-000 and RM05-25-000 - 865 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 866 - 

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 fixed-dollar 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 867 - 

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 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 termination868 of the power purchase agreement as a designated network 

 868 As 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 868 - 

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. 

 

terminated, it must comport with the requirements for LD provisions, and all other 

requirements for designation of network resources, before it can be redesignated. 

869 As 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 869 - 

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” 
Docket Nos. RM05-17-000 and RM05-25-000 - 870 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 871 - 

(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 

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 

 870 Northwest Parties request similar clarification for designation of purchase 

contracts from one or more specified, individual resources. 
Docket Nos. RM05-17-000 and RM05-25-000 - 872 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 873 - 

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.” 
Docket Nos. RM05-17-000 and RM05-25-000 - 874 - 

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 flow-based 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 875 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 876 - 

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 to designate as network resources 

contracts that may be relatively long-term, 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 off-system transactions, including sourcing from owned generation 
Docket Nos. RM05-17-000 and RM05-25-000 - 877 - 

located off-system. We therefore use the term “off-system 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 off-system 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 878 - 

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 

 871 18 CFR 37.6. 
Docket Nos. RM05-17-000 and RM05-25-000 - 879 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 880 - 

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 

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 

 872 102 FERC ¶ 61,257 at P 14. 
Docket Nos. RM05-17-000 and RM05-25-000 - 881 - 

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 flow-based 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 882 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 883 - 

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. 888873 and that the resource designation requirements do not deny 

 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.” 
Docket Nos. RM05-17-000 and RM05-25-000 - 884 - 

LSEs any right to use their transmission, but rather prescribe how they are to implement 

that right. 

1488. EEI, Nevada Companies, PNM-TNMP 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 state-mandated 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 stateregulated 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, 

 874 176 F.3d 1090, 1096 (8th Cir. 1999), cert. denied, 528 U.S. 1182 (2000). 
Docket Nos. RM05-17-000 and RM05-25-000 - 885 - 

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, 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 

 875 Florida Power Corp, 81 FERC ¶ 61,247 (1997) (Florida Power). 
Docket Nos. RM05-17-000 and RM05-25-000 - 886 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 887 - 

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 statemandated 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 888 - 

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; 
Docket Nos. RM05-17-000 and RM05-25-000 - 889 - 

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, 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 890 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 891 - 

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 conditional-firm 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 892 - 

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. 

 876 See 18 CFR 37.6(a). 

877 See, e.g., Entergy Services, Inc., 105 FERC ¶ 61,318 (2003), reh’g denied in 

relevant part, 109 FERC ¶ 61,216 (2004). 
Docket Nos. RM05-17-000 and RM05-25-000 - 893 - 

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 third-party 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 894 - 

unsuccessful, the Commission further 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 895 - 

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 

 878 E.g., Ameren, Entegra, Pinnacle, Public Power Council, and Southern. 

879 See Investigation of Terms and Conditions of Public Utility Market-Based Rate 

Authorizations, 105 FERC ¶ 61,218 (2003). 
Docket Nos. RM05-17-000 and RM05-25-000 - 896 - 

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 have not 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. 

 880 E.g., Ameren, EEI, Suez Energy NA, Nevada Companies, and Utah 

Municipals. 

881 E.g., Ameren, Duke Reply, Entergy, and Pinnacle. 
Docket Nos. RM05-17-000 and RM05-25-000 - 897 - 

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 

 882 E.g., EEI, TDU Systems, Indianapolis Power Reply, and South Carolina E&G 

Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 898 - 

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 self-report 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 

 883 E.g., EEI and Indianapolis Power Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 899 - 

that it has neither the data nor the personnel 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. 

 884 E.g., MISO, Indianapolis Power Reply, and Detroit Edison Reply. 
Docket Nos. RM05-17-000 and RM05-25-000 - 900 - 

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.” 
Docket Nos. RM05-17-000 and RM05-25-000 - 901 - 

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 

 885 See supra note 75. 

886 Policy Statement on Enforcement at P 13. 
Docket Nos. RM05-17-000 and RM05-25-000 - 902 - 

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-bycase 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 

 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 903 - 

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 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 thirdparty'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 
Docket Nos. RM05-17-000 and RM05-25-000 - 904 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 905 - 

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 preconfirmed, 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 906 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 907 - 

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 short-term basis to make offsystem 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

 890 Order No. 888-B at 62,093. 

891 The general term “undesignation” refers to both temporary terminations and 

indefinite terminations of network resource status, as discussed below. 
Docket Nos. RM05-17-000 and RM05-25-000 - 908 - 

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. 

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 shortterm 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 909 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 910 - 

(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 
Docket Nos. RM05-17-000 and RM05-25-000 - 911 - 

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 

 892 18 CFR 37.6. 

893 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 912 - 

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-à-vis point-to-point 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 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. 

 894 E.g., Duke, EEI, Entergy, Progress Energy, South Carolina E&G Reply, and 

TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 913 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 914 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 915 - 

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 off-system 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 off-system 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 

 895 See, e.g., Order No. 2003 at P 118, 744. 
Docket Nos. RM05-17-000 and RM05-25-000 - 916 - 

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-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 917 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 918 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 919 - 

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-to-point 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-to-point 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 

 896 E.g., EEI, NRECA Reply, PNM-TNMP, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 920 - 

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 off-system 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 off-system 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 921 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 922 - 

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 

 897 See Virginia Electric and Power Co., 81 FERC ¶ 61,125 at 61,111-12 (1997), 

reh’g denied, 82 FERC ¶ 61,034 (1998). 
Docket Nos. RM05-17-000 and RM05-25-000 - 923 - 

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 

 898 E.g., EEI, Pinnacle, and Progress Energy. 
Docket Nos. RM05-17-000 and RM05-25-000 - 924 - 

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-topoint 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 925 - 

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 pointto-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. 

 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 926 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 927 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 928 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 929 - 

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 

 900 93 FERC ¶ 61,331 at 62,128 (2000). 
Docket Nos. RM05-17-000 and RM05-25-000 - 930 - 

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 third-party 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 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 931 - 

network resources, we find that situations where undesignations cannot be 

accommodated due to transmission constraints should be extremely rare, such as highlyextraordinary 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 

 901 18 CFR 37.6(e)(2). 
Docket Nos. RM05-17-000 and RM05-25-000 - 932 - 

“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, pointto-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-topoint 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 933 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 934 - 

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 off-system 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 

 902 Order No. 888 at 31,751. 

903 Idaho Power Co., 103 FERC ¶ 61,182 at P 2 (2003) (Idaho Power). 

904 Id. at P 4. 
Docket Nos. RM05-17-000 and RM05-25-000 - 935 - 

load priority 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-to-point 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 offsystem 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. 

 905 Id.

906 MidAmerican Energy Co., 112 FERC ¶ 61,346 at P 6 (2005).
Docket Nos. RM05-17-000 and RM05-25-000 - 936 - 

(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. 

 907 E.g., Alberta Intervenors, Southern, Suez Energy NA, and TAPS. 

908 E.g., EEI, Entergy, Northwest Parties, NRECA, Pinnacle, PGP, Southern, and 

Xcel. 
Docket Nos. RM05-17-000 and RM05-25-000 - 937 - 

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 Commission-regulated 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 938 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 939 - 

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 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 

 909 MidAmerican Energy Co., 112 FERC ¶ 61,346 at P 6 (2005) (MidAmerican). 

Following an audit, the Commission found that MidAmerican’s wholesale merchant 

function used network service instead of point-to-point service to deliver short-term 

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 off-system sales. Id. at P 6. The modifications to section 28.4 

adopted in this Final Rule do not alter that limitation. 
Docket Nos. RM05-17-000 and RM05-25-000 - 940 - 

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 nondesignated 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 941 - 

Comments

1605. TDU Systems request 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 state 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 lower-priority secondary service to have a scheduling 

advantage over non-firm transmission would be inappropriate and would discourage the 

use of non-firm transmission service, thereby minimizing the revenue credits from nonfirm transmission service that benefit all firm transmission customers. 
Docket Nos. RM05-17-000 and RM05-25-000 - 942 - 

(3) Redirect of Network Service

1607. The current pro forma OATT does not include any provision to change the point 

of receipt for an off-system designated network resource in a manner similar to redirect 

of point-to-point service. We are aware, however, that several transmission providers 

have posted business practices that allow network customers either to substitute an offsystem 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 943 - 

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-to-point 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 off-system 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-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 944 - 

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 

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 

 910 Order No. 888-A at 30,216. 
Docket Nos. RM05-17-000 and RM05-25-000 - 945 - 

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 

 911 Order No. 888 at 31,736. 

912 Order No. 888-A at 30,258-61. 
Docket Nos. RM05-17-000 and RM05-25-000 - 946 - 

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-

 913 E.g., TAPS, TDU Systems, AMP-Ohio, and CAC/EPUC. 

914 TDU 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). 

915 E.g., AMP-Ohio, CAC/EPUC, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 947 - 

Ohio argues that it is inappropriate to assign a full load ratio share of transmission-related 

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 

 916 Citing 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). 

917 E.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)). 

918 This settlement agreement was accepted in PJM Interconnection, L.L.C., 

113 FERC ¶ 61,279 (2005). 
Docket Nos. RM05-17-000 and RM05-25-000 - 948 - 

1618. Further, both TAPS and AMP-Ohio 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 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 

 919 PJM Interconnection, L.L.C., 113 FERC ¶ 63,024 (2005). 
Docket Nos. RM05-17-000 and RM05-25-000 - 949 - 

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 point-to-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 

 920 We 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. 

921 Order No. 888-A at 30,260-61. 
Docket Nos. RM05-17-000 and RM05-25-000 - 950 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 951 - 

1622. Southern and other commenters922 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 point-to-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 

 922 PNM-TNMP and TranServ. 
Docket Nos. RM05-17-000 and RM05-25-000 - 952 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 953 - 

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. 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 954 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 955 - 

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 

 923 See 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-topoint customers, the transmission provider must compute its bill to an interrupted nonfirm 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 956 - 

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 

 

daily reservation was interrupted after ten hours, its bill must be computed using the 

hourly rate applied to ten hours of service. 
Docket Nos. RM05-17-000 and RM05-25-000 - 957 - 

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-to-point customer. Accordingly, we decline to adopt Seattle’s proposal. We 

discuss redispatch issues more broadly in section V.D.1 of this Final Rule. 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 958 - 

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, 

 924 E.g., Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985). 

925 See, 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 959 - 

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 

 926 Policy Statement on Electric Creditworthiness, 109 FERC ¶ 61,186 (2004) 

(Creditworthiness Policy Statement). 
Docket Nos. RM05-17-000 and RM05-25-000 - 960 - 

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 

 927 The 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 noncreditworthy determination. 

928 E.g., ISO/RTO Council, CAISO, LDWP, MISO/PJM States, PGP, and PNMTNMP. 
Docket Nos. RM05-17-000 and RM05-25-000 - 961 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 962 - 

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 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 

 929 E.g., CAISO, EEI, MidAmerican, MISO/PJM States, Nevada Companies, PJM, 

Powerex, Santa Clara, Suez Energy NA, TDU Systems, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 963 - 

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 non-discriminatory 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 two-part creditworthiness assessment in order to facilitate non-burdensome and fair 

assessment of creditworthiness. TAPS recommends that a standard similar to the Florida 

 

930 E.g., APPA, East Texas Cooperatives, Lassen, MISO/PJM States, Nevada Companies, 

NRECA, PGP, Powerex, Southern, Suez Energy NA, TANC, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 964 - 

Power Corp. OATT be applied, which provides that customers with “satisfactory longterm 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. 

 931 See NOPR at P 456. 
Docket Nos. RM05-17-000 and RM05-25-000 - 965 - 

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 onemonth 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 Act932 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 

 932 16 U.S.C. 831n-4. 

933Citing East Ky. Power Coop., Inc., 114 FERC ¶ 61,035 at P 56 (2006). 
Docket Nos. RM05-17-000 and RM05-25-000 - 966 - 

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 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, ISO-New England states that this rulemaking 

 934 E.g., MidAmerican, Southern, PNM-TNMP, NorthWestern, and Xcel. 

935 E.g., PNM-TNMP, EEI, and MidAmerican. 

936 Southern states that it already includes creditworthiness and security 

requirements in its OATT since the Commission issued its Creditworthiness Policy 

Statement. 
Docket Nos. RM05-17-000 and RM05-25-000 - 967 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 968 - 

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 website 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” 

 937 California 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 969 - 

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 

websites 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 

 938 See, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 970 - 

that transmission service is provided to customers, to be detailed, clearly stated on the 

transmission provider’s public website, 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 

 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/contact-us/enforce-hot.asp. 

940 With 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 website. In such instances, we expect that the transmission provider 

will reference any NAESB practices it uses and provide a link on its public website to the 

NAESB website in order to provide interested parties with a means to access the 

copyrighted material. 
Docket Nos. RM05-17-000 and RM05-25-000 - 971 - 

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 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 

 941 The 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). 

942 See, 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 972 - 

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 website (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 

 943 As 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 973 - 

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 

 944 As 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 974 - 

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 noncreditworthy 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 975 - 

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 that describe and 

implement its creditworthiness and security policies. 
Docket Nos. RM05-17-000 and RM05-25-000 - 976 - 

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 

 945 Order No. 888-B at 62,081. 
Docket Nos. RM05-17-000 and RM05-25-000 - 977 - 

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 commenters946 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 

 946 E.g., Southern, EEI, and Northwest IOUs 
Docket Nos. RM05-17-000 and RM05-25-000 - 978 - 

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 

 947 Citing Article 18, Large Generator Interconnection Agreement; ANR Pipeline 

Co., 98 FERC ¶ 61,218, order on tariff filing, 100 FERC ¶ 61,132 (2002). 
Docket Nos. RM05-17-000 and RM05-25-000 - 979 - 

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 

 948 Citing Southwest Power Pool, Inc., 112 FERC ¶ 61,100 at P 39 (2005). 
Docket Nos. RM05-17-000 and RM05-25-000 - 980 - 

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 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 

 949 Citing Order No. 888-A at 30,301. 
Docket Nos. RM05-17-000 and RM05-25-000 - 981 - 

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 

 950 See Entegra Reply (citing Southern Company Services, Inc., 113 FERC 

¶ 61,239 (2005)). 
Docket Nos. RM05-17-000 and RM05-25-000 - 982 - 

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. 

 951 See Order No. 888-A at 30,301 and Order No. 888-B at 62,081 (section 10.2 of 

the pro forma OATT). 

952 Order No. 888-A at 30,301. 

953 Order No. 888-B at 62,081. 

954 See, e.g., Northeast Utilities Services Co., 111 FERC ¶ 61,333 (2005) 

(Northeast Utilities). 
Docket Nos. RM05-17-000 and RM05-25-000 - 983 - 

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 

 955 Order No. 888 at 31,765. 

956 Order No. 2003 at P 636; Order No. 2003-A at 31,162. 
Docket Nos. RM05-17-000 and RM05-25-000 - 984 - 

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 

 957 Policy Statement on Matters Related to Bulk Power System Reliability, 107 

FERC ¶ 61,052 (2004) (Reliability Policy Statement). 

958 Reliability Policy Statement at P 40 (citations omitted). 
Docket Nos. RM05-17-000 and RM05-25-000 - 985 - 

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 change in 

circumstances vis-à-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 

 959 112 FERC ¶ 61,100 at P 39 (2005). 

960 113 FERC ¶ 61,239 at P 7 (2005). 
Docket Nos. RM05-17-000 and RM05-25-000 - 986 - 

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 to 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 987 - 

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 

 961 Order No. 888-A at 30,286 and 30,366. 
Docket Nos. RM05-17-000 and RM05-25-000 - 988 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 989 - 

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 

 962 Section 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.” 
Docket Nos. RM05-17-000 and RM05-25-000 - 990 - 

either the buyer or seller.” The Commission also proposed to clarify that, for the 

purposes of applying 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 991 - 

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 non-interruptible 

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 non-firm, 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 nonfirm 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 992 - 

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 pre-confirmed, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 993 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 994 - 

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 nonnetwork 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 non-network 

resources and secondary network service to serve part, or even 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 995 - 

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-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 
Docket Nos. RM05-17-000 and RM05-25-000 - 996 - 

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 

 963 See Order No. 888 at 31,736; Order No. 888-A at 30,259. 
Docket Nos. RM05-17-000 and RM05-25-000 - 997 - 

reservation. Powerex believes that these two types of service could be described as nonfirm, non-interruptible (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 
Docket Nos. RM05-17-000 and RM05-25-000 - 998 - 

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-to-point 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 999 - 

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 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1000 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1001 - 

that the current definition of long-term firm point-to-point 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 long-term 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. 

 964 Redirect-related issues are addressed in section V.D.4. 

965 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 1002 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1003 - 

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 

 966 See 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). 

967 E.g., APPA, AWEA, EEI, Morgan Stanley, NRG, Southern, TAPS, and 

Williams. 

968 E.g., Ameren, PNM-TNMP, and South Carolina E&G. In reply comments, 

TDU Systems urge the Commission to reject this contention. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1004 - 

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 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 non-RTO 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1005 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1006 - 

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 

 969 See, e.g., Duke Power, 113 FERC ¶ 61,288 (2005); MidAmerican Energy 

Holdings Co., 113 FERC ¶ 61,298 (2005). 
Docket Nos. RM05-17-000 and RM05-25-000 - 1007 - 

separation of functions regulation970 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 

 970 18 CFR 385.2202. 

971 Statement of Administrative Policy on Separation of Functions, 101 FERC 

¶ 61,340 at P 24-26 (2002). 

972 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 1008 - 

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 thirdparty 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. 

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 third-party 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 

 973 E.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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1009 - 

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 Antimanipulation 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 

 974 Prohibition of Energy Market Manipulation, III FERC Stats. & Regs. ¶ 31,202 

(2006), order denying rehearing, 114 FERC ¶ 61,300 (2006). 

975 NOPR at P 384. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1010 - 

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 

 976 E.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. 

977 E.g., Arkansas Commission and ELCON. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1011 - 

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 

 978 Wisconsin 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). 

979 E.g., Nevada Companies and PNM-TNMP. 

980 EEI 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 non-cooperative.” Contested Audit Matters at P 35. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1012 - 

actions taken for reliability purposes that are consistent with good utility practice. PNMTNMP 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 vertically-integrated 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 

 981 16 U.S.C. 824q(k). 

982 Policy Statement on Enforcement at P 1. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1013 - 

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 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 

 983 Id. at P 13. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1014 - 

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 nonprofit 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 

 984 We 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). 

985 Rules 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 1015 - 

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 

 986 Policy 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). 

987 Citing Contested Audit Matters at P 35. 

988 Policy Statement on Enforcement at P 26. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1016 - 

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 attorney-client 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 

 989 See 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 1017 - 

violation and the entity’s market-based rate authority. The Commission also proposed 

that if it determines, as a result of a significant OATT violation, to revoke the marketbased 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 market-based 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, 

 990 E.g., EEI, ELCON, Morgan Stanley, Nevada Companies, Northwest IOUs, 

Progress Energy, PNM-TNMP, Sempra Global, Southern, and TDU Systems. 

991 E.g., EEI, Nevada Companies, Northwest IOUs, Progress Energy, PNMTNMP, Sempra Global, and Southern. 

992 E.g., APPA. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1018 - 

it should clarify what constitutes a “nexus” between an OATT violation and an entity’s 

market-based 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 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” 

 993 E.g., APPA, EPSA, and TAPS. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1019 - 

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 cost-based 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 marketbased 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 marketbased rate authority as a result of the transmission provider’s OATT violation. NRECA 

replies that market-based 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. 

 994 E.g., EEI, Nevada Companies, Northwest IOUs, Progress Energy, PNMTNMP, Sempra Global, and Southern. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1020 - 

1742. APPA also suggests that, short of revocation of a transmission provider’s marketbased 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1021 - 

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 market-based 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 market-based 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1022 - 

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 market-based 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 affiliate abuse or reciprocal dealing.995 In particular, we have long held that 

 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 1023 - 

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 marketbased 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 

 

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). 

996 We 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 1024 - 

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 marketbased 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 

 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1025 - 

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 

 997 APPA, Nevada Companies, PNM-TNMP, Southwestern Coop, and TDU 

Systems. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1026 - 

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 

 998 Similarly, 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). 
Docket Nos. RM05-17-000 and RM05-25-000 - 1027 - 

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 

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

 1001 These burden estimates applied only to the Final Rule and do not reflect upon 

all of FERC-516 or FERC-717. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1028 - 

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

Creditworthines

s – 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 

 Review and 

comment by 

utility 

 

Implementation 

by each utility 

1

116

116

1

1

1

1,920 

20 

40 

1,920

2,320

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
Docket Nos. RM05-17-000 and RM05-25-000 - 1029 - 

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)) 
Docket Nos. RM05-17-000 and RM05-25-000 - 1030 - 

Recordkeeping = $7,478,888 

Labor (file/record clerk @ $17 an hour) 4,640 hours @$17/hour = $78,880 

Storage 8,000 sq. ft. x $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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1031 - 

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 

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, N.E., 

Washington, D.C. 20426, Attention: Michael Miller, Office of the Executive Director, 

Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1032 - 

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, N.W., Washington, D.C. 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 e-mail 

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 

 1002 Regulations Implementing the National Environmental Policy Act, Order No. 

486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). 
Docket Nos. RM05-17-000 and RM05-25-000 - 1033 - 

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 

 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.

1007 The 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 

(continued) 
Docket Nos. RM05-17-000 and RM05-25-000 - 1034 - 

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 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington D.C. 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, 

 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1035 - 

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 (e-mail 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 [insert date 60 days after publication in the 

FEDERAL REGISTER]. 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1036 - 

18 CFR Part 37

 Conflict of interests, Electric power plants, Electric utilities, Reporting and 

recordkeeping requirements 

By the Commission. 

(S E A L ) 

Magalie R. Salas, 

 Secretary. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1037 - 

In consideration of the foregoing, the Commission amends parts 35 and 37, 

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. ¶ ___ 
Docket Nos. RM05-17-000 and RM05-25-000 - 1038 - 

(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. ¶ _____. 

(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. ¶ ___, 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 [insert 60 days after date of 

publication of the Final Rule in the FEDERAL REGISTER], it must file the revisions to 

the pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ ____, 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 ¶ ____. 

(iii) If a public utility owns, controls, or operates transmission facilities used for 

the transmission of electric energy in interstate commerce as of [insert 60 days after date 

of publication of the Final Rule in the FEDERAL REGISTER], 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1039 - 

public utility's share of the jointly owned facilities must file no later than [insert 60 days 

after date of publication of the Final Rule in the FEDERAL REGISTER] the revisions to 

the pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ ____, 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 Commission-approved 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. ¶ _____, 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. ¶ _____. 

(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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1040 - 

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 noneconomy 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. ¶ ___, 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. ¶ _____. 

 (i) For any power pool, public utility holding company or other multi-lateral 
Docket Nos. RM05-17-000 and RM05-25-000 - 1041 - 

arrangement or agreement that contains transmission rates, terms or conditions and that is 

executed after [insert 60 days after date of publication of the Final Rule in the FEDERAL 

REGISTER], 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 [insert 60 days after date of publication of the Final Rule in the 

FEDERAL REGISTER], 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. ¶ ____, 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 ¶ ____. 

 (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. 

 (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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1042 - 

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. ¶ ___, 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. ¶ _____. 

(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. ¶ ____, 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 ¶ ____. 

(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. ¶ ____, or any portions thereof, the 

Commission-approved 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 ¶ ____. 

(d) Waivers. * * * 

 
Docket Nos. RM05-17-000 and RM05-25-000 - 1043 - 

(1) No later than [insert 60 days after date of publication of the Final Rule in the 

FEDERAL REGISTER], or 

* * * * * 

(e) Non-public utility procedures for tariff reciprocity compliance. (1) A 

non-public 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. ¶ _____. 

* * * * * 

 (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 nonpublic 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1044 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1045 - 

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 Commissionapproved Reliability Standards. 

 (vii) Capacity Benefit Margin or CBM means the amount of TTC preserved by 

the Transmission Provider for load-serving 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1046 - 

(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 off-peak periods in its tariff, ATC, TTC, CBM, and TRM will be posted 

daily for each period. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1047 - 

 (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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1048 - 

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) 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1049 - 

(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 

websites. 

* * * * * 

 (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. 

* * * * * 
Docket Nos. RM05-17-000 and RM05-25-000 - 1050 - 

 (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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1051 - 

(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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1052 - 

(2) * * * 

(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-topoint 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1053 - 

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.
Docket Nos. RM05-17-000 and RM05-25-000 - 1054 - 

(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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 1055 - 

(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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1056 - 

 (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, 
Docket Nos. RM05-17-000 and RM05-25-000 - 1057 - 

(B) Number of transmission service requests withdrawn from the 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1058 - 

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-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. 

(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 employee-hours 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1059 - 

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-to-point, 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1060 - 

(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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1061 - 

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 website at the following location 

http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp. 

Deadline 

(days after 

publication 

in Fed. Reg.) Compliance Action 

Final Rule 

Paragraph 

# 

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 

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 website 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1062 - 

Deadline 

(days after 

publication 

in Fed. Reg.) Compliance Action 

Final Rule 

Paragraph 

# 

 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1063 - 

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 Allliance 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1064 - 

Abbreviation Initial Commenters 

BART San Francisco Bay Area Rapid Transit District 

Bonneville Bonneville Power Administration 

BP Energy BP Energy Company 

Bureau of Reclamation US 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 

ColumbiaGrid 

ColumbiaGrid Members (Bonneville Power 

Administration; Avista Corp.; Public Utility District 

No. 1 of Chelan County, Washington; Publicy Utility 

District No. 2 of Grant County, Washington; Puget 

Sound Energy, Inc.; Seattle City Light; and Tacoma 

Power 
Docket Nos. RM05-17-000 and RM05-25-000 - 1065 - 

Abbreviation Initial Commenters 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1066 - 

Abbreviation Initial Commenters 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1067 - 

Abbreviation Initial Commenters 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1068 - 

Abbreviation Initial Commenters 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1069 - 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1070 - 

Abbreviation Initial Commenters 

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 TexasNew 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) 
Docket Nos. RM05-17-000 and RM05-25-000 - 1071 - 

Abbreviation Initial Commenters 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1072 - 

Abbreviation Initial Commenters 

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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1073 - 

Abbreviation Initial Commenters 

Western Governors Western Governors’ Association 

Williams Williams Power Company, Inc. 

Wisconsin Electric Wisconsin Electric Power Company 

WSPP Western Systems Power Pool, Inc. 

Xcel Xcel Energy Services, Inc. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1074 - 

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; Publicy 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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1075 - 

Abbreviation Reply Commenters 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1076 - 

Abbreviation Reply Commenters 

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

 1008 A “*” indicates that the composition of this group has altered in the reply 

comment filing. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1077 - 

Abbreviation Reply Commenters 

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 

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 PowerOhio, 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1078 - 

Abbreviation Reply Commenters 

PJM PJM Interconnection, LLC 

PNM-TNMP Public Service Company of New Mexico and TexasNew 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1079 - 

Abbreviation Reply Commenters 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1080 - 

 

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 

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) 

 1009 A “◊” indicates that this party submitted speaker materials at the October 12 

Technical Conference. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1081 - 

Abbreviation Technical Conference Commenters 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1082 - 

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. 
Docket Nos. RM05-17-000 and RM05-25-000 - 1083 - 

Abbreviation Supplemental Commenters 

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 TexasNew 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 
Docket Nos. RM05-17-000 and RM05-25-000 - 1084 - 

Abbreviation Supplemental Commenters 

South Carolina E&G South Carolina Electric & Gas Company 

South Carolina 

Regulatory Staff South Carolina Office of Regulatory Staff 

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. 

 1010A “*” indicates that the composition of this group has altered in this filing.. 
 

 Appendix C

RM05-17-000 & RM05-25-000 

(Issued) 

PRO FORMA OPEN ACCESS 

TRANSMISSION TARIFF 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 2 

TABLE OF CONTENTS 

I. COMMON SERVICE PROVISIONS...................................................................10

1 DEFINITIONS...........................................................................................................10

1.1 Affiliate:.........................................................................................................10

1.2 Ancillary Services: ........................................................................................10

1.3 Annual Transmission Costs:..........................................................................10

1.4 Application: ...................................................................................................10

1.5 Commission:..................................................................................................11

1.6 Completed Application:.................................................................................11

1.7 Control Area: .................................................................................................11

1.8 Curtailment:...................................................................................................11

1.9 Delivering Party:............................................................................................12

1.10 Designated Agent: .........................................................................................12

1.11 Direct Assignment Facilities: ........................................................................12

1.12 Eligible Customer:.........................................................................................12

1.13 Facilities Study: .............................................................................................13

1.14 Firm Point-To-Point Transmission Service:..................................................13

1.15 Good Utility Practice:....................................................................................14

1.16 Interruption:...................................................................................................14

1.17 Load Ratio Share: ..........................................................................................14

1.18 Load Shedding:..............................................................................................15

1.19 Long-Term Firm Point-To-Point Transmission Service: ..............................15

1.20 Native Load Customers: ................................................................................15

1.21 Network Customer:........................................................................................15

1.22 Network Integration Transmission Service:..................................................15

1.23 Network Load:...............................................................................................16

1.24 Network Operating Agreement: ....................................................................16

1.25 Network Operating Committee: ....................................................................16

1.26 Network Resource: ........................................................................................17

1.27 Network Upgrades:........................................................................................17

1.28 Non-Firm Point-To-Point Transmission Service: .........................................17

1.29 Non-Firm Sale: ..............................................................................................17

1.30 Open Access Same-Time Information System (OASIS): .............................18

1.31 Part I: .............................................................................................................18

1.32 Part II: ............................................................................................................18

1.33 Part III:...........................................................................................................18

1.34 Parties: ...........................................................................................................18

1.35 Point(s) of Delivery: ......................................................................................19
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 3 

1.36 Point(s) of Receipt:........................................................................................19

1.37 Point-To-Point Transmission Service: ..........................................................19

1.38 Power Purchaser: ...........................................................................................19

1.39 Pre-Confirmed Application: ..........................................................................20

1.40 Receiving Party: ............................................................................................20

1.41 Regional Transmission Group (RTG): ..........................................................20

1.42 Reserved Capacity:........................................................................................20

1.43 Service Agreement: .......................................................................................21

1.44 Service Commencement Date: ......................................................................21

1.45 Short-Term Firm Point-To-Point Transmission Service:..............................21

1.46 System Condition ..........................................................................................21

1.47 System Impact Study:....................................................................................22

1.48 Third-Party Sale:............................................................................................22

1.49 Transmission Customer:................................................................................22

1.50 Transmission Provider:..................................................................................22

1.51 Transmission Provider's Monthly Transmission System Peak: ....................23

1.52 Transmission Service:....................................................................................23

1.53 Transmission System:....................................................................................23

2 INITIAL ALLOCATION AND RENEWAL PROCEDURES..............................................23

2.1 Initial Allocation of Available Transfer Capability: .....................................23

2.2 Reservation Priority For Existing Firm Service Customers:.........................24

3 ANCILLARY SERVICES ...........................................................................................25

3.1 Scheduling, System Control and Dispatch Service:......................................27

3.2 Reactive Supply and Voltage Control from Generation or Other Sources 

Service: ......................................................................................................................28

3.3 Regulation and Frequency Response Service: ..............................................28

3.4 Energy Imbalance Service:............................................................................28

3.5 Operating Reserve - Spinning Reserve Service: ...........................................28

3.6 Operating Reserve - Supplemental Reserve Service:....................................28

3.7 Generator Imbalance Service: .......................................................................28

4 OPEN ACCESS SAME-TIME INFORMATION SYSTEM (OASIS)................................28

5 LOCAL FURNISHING BONDS...................................................................................29

5.1 Transmission Providers That Own Facilities Financed by Local Furnishing 

Bonds: 30

5.2 Alternative Procedures for Requesting Transmission Service:.....................30

6 RECIPROCITY..........................................................................................................31

7 BILLING AND PAYMENT .........................................................................................33
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 4 

7.1 Billing Procedure:..........................................................................................33

7.2 Interest on Unpaid Balances:.........................................................................33

7.3 Customer Default:..........................................................................................34

8 ACCOUNTING FOR THE TRANSMISSION PROVIDER'S USE OF THE TARIFF..............34

8.1 Transmission Revenues:................................................................................35

8.2 Study Costs and Revenues: ...........................................................................35

9 REGULATORY FILINGS ...........................................................................................35

10 FORCE MAJEURE AND INDEMNIFICATION..............................................................36

10.1 Force Majeure:...............................................................................................36

10.2 Indemnification:.............................................................................................37

11 CREDITWORTHINESS ..............................................................................................37

12 DISPUTE RESOLUTION PROCEDURES .....................................................................37

12.1 Internal Dispute Resolution Procedures:.......................................................37

12.2 External Arbitration Procedures:...................................................................38

12.3 Arbitration Decisions:....................................................................................39

12.4 Costs: .............................................................................................................39

12.5 Rights Under The Federal Power Act: ..........................................................40

II. POINT-TO-POINT TRANSMISSION SERVICE...............................................40

13 NATURE OF FIRM POINT-TO-POINT TRANSMISSION SERVICE ...............................40

13.1 Term: .............................................................................................................40

13.2 Reservation Priority:......................................................................................40

13.3 Use of Firm Transmission Service by the Transmission Provider:...............43

13.4 Service Agreements:......................................................................................43

13.5 Transmission Customer Obligations for Facility Additions or Redispatch 

Costs: 44

13.6 Curtailment of Firm Transmission Service: ..................................................46

13.7 Classification of Firm Transmission Service: ...............................................47

13.8 Scheduling of Firm Point-To-Point Transmission Service: ..........................49

14 NATURE OF NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE ......................51

14.1 Term: .............................................................................................................51

14.2 Reservation Priority:......................................................................................51

14.3 Use of Non-Firm Point-To-Point Transmission Service by the Transmission 

Provider: ....................................................................................................................52

14.4 Service Agreements:......................................................................................53

14.5 Classification of Non-Firm Point-To-Point Transmission Service:..............53

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service:..................54

14.7 Curtailment or Interruption of Service: .........................................................55
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 5 

15 SERVICE AVAILABILITY.........................................................................................57

15.1 General Conditions:.......................................................................................57

15.2 Determination of Available Transfer Capability:..........................................57

15.3 Initiating Service in the Absence of an Executed Service Agreement:.........58

15.4 Obligation to Provide Transmission Service that Requires Expansion or 

Modification of the Transmission System, Redispatch or Conditional Curtailment:58

15.5 Deferral of Service: .......................................................................................61

15.6 Other Transmission Service Schedules: ........................................................61

15.7 Real Power Losses:........................................................................................61

16 TRANSMISSION CUSTOMER RESPONSIBILITIES ......................................................62

16.1 Conditions Required of Transmission Customers:........................................62

16.2 Transmission Customer Responsibility for Third-Party Arrangements:.......63

17 PROCEDURES FOR ARRANGING FIRM POINT-TO-POINT TRANSMISSION SERVICE 63

17.1 Application: ...................................................................................................63

17.2 Completed Application:.................................................................................64

17.3 Deposit:..........................................................................................................66

17.4 Notice of Deficient Application: ...................................................................68

17.5 Response to a Completed Application: .........................................................68

17.6 Execution of Service Agreement:..................................................................69

17.7 Extensions for Commencement of Service: ..................................................69

18 PROCEDURES FOR ARRANGING NON-FIRM POINT-TO-POINT TRANSMISSION 

SERVICE .........................................................................................................................70

18.1 Application: ...................................................................................................70

18.2 Completed Application:.................................................................................71

18.3 Reservation of Non-Firm Point-To-Point Transmission Service:.................72

18.4 Determination of Available Transfer Capability:..........................................73

19 ADDITIONAL STUDY PROCEDURES FOR FIRM POINT-TO-POINT TRANSMISSION 

SERVICE REQUESTS........................................................................................................73

19.1 Notice of Need for System Impact Study:.....................................................74

19.2 System Impact Study Agreement and Cost Reimbursement: .......................75

19.3 System Impact Study Procedures:.................................................................76

19.4 Facilities Study Procedures: ..........................................................................78

19.5 Facilities Study Modifications:......................................................................79

19.6 Due Diligence in Completing New Facilities:...............................................80

19.7 Partial Interim Service:..................................................................................80

19.8 Expedited Procedures for New Facilities: .....................................................81

19.9 Penalties for Failure to Meet Study Deadlines:.............................................82

20 PROCEDURES IF THE TRANSMISSION PROVIDER IS UNABLE TO COMPLETE NEW 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 6 

TRANSMISSION FACILITIES FOR FIRM POINT-TO-POINT TRANSMISSION SERVICE........84

20.1 Delays in Construction of New Facilities:.....................................................84

20.2 Alternatives to the Original Facility Additions: ............................................84

20.3 Refund Obligation for Unfinished Facility Additions:..................................85

21 PROVISIONS RELATING TO TRANSMISSION CONSTRUCTION AND SERVICES ON THE 

SYSTEMS OF OTHER UTILITIES ......................................................................................86

21.1 Responsibility for Third-Party System Additions:........................................86

21.2 Coordination of Third-Party System Additions: ...........................................86

22 CHANGES IN SERVICE SPECIFICATIONS..................................................................87

22.1 Modifications On a Non-Firm Basis: ............................................................87

22.2 Modification On a Firm Basis: ......................................................................88

23 SALE OR ASSIGNMENT OF TRANSMISSION SERVICE ..............................................89

23.1 Procedures for Assignment or Transfer of Service: ......................................89

23.2 Limitations on Assignment or Transfer of Service: ......................................90

23.3 Information on Assignment or Transfer of Service: .....................................90

24 METERING AND POWER FACTOR CORRECTION AT RECEIPT AND DELIVERY 

POINTS(S) .......................................................................................................................91

24.1 Transmission Customer Obligations: ............................................................91

24.2 Transmission Provider Access to Metering Data:.........................................91

24.3 Power Factor:.................................................................................................91

25 COMPENSATION FOR TRANSMISSION SERVICE ......................................................92

26 STRANDED COST RECOVERY .................................................................................92

27 COMPENSATION FOR NEW FACILITIES AND REDISPATCH COSTS ..........................92

III. NETWORK INTEGRATION TRANSMISSION SERVICE .............................93

28 NATURE OF NETWORK INTEGRATION TRANSMISSION SERVICE ............................93

28.1 Scope of Service:...........................................................................................93

28.2 Transmission Provider Responsibilities: .......................................................94

28.3 Network Integration Transmission Service:..................................................95

28.4 Secondary Service: ........................................................................................95

28.5 Real Power Losses:........................................................................................96

28.6 Restrictions on Use of Service: .....................................................................96

29 INITIATING SERVICE...............................................................................................96

29.1 Condition Precedent for Receiving Service: .................................................97

29.2 Application Procedures: ................................................................................97

29.3 Technical Arrangements to be Completed Prior to Commencement of 

Service: ....................................................................................................................104
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 7 

29.4 Network Customer Facilities:......................................................................104

29.5 Filing of Service Agreement: ......................................................................105

30 NETWORK RESOURCES ........................................................................................105

30.1 Designation of Network Resources:............................................................105

30.2 Designation of New Network Resources: ...................................................105

30.3 Termination of Network Resources: ...........................................................106

30.4 Operation of Network Resources: ...............................................................108

30.5 Network Customer Redispatch Obligation:.................................................109

30.6 Transmission Arrangements for Network Resources Not Physically 

Interconnected With The Transmission Provider:...................................................110

30.7 Limitation on Designation of Network Resources:.....................................110

30.8 Use of Interface Capacity by the Network Customer: ................................110

30.9 Network Customer Owned Transmission Facilities:...................................111

31 DESIGNATION OF NETWORK LOAD ......................................................................112

31.1 Network Load:.............................................................................................112

31.2 New Network Loads Connected With the Transmission Provider: ............112

31.3 Network Load Not Physically Interconnected with the Transmission 

Provider: ..................................................................................................................112

31.4 New Interconnection Points: .......................................................................113

31.5 Changes in Service Requests:......................................................................113

31.6 Annual Load and Resource Information Updates: ......................................114

32 ADDITIONAL STUDY PROCEDURES FOR NETWORK INTEGRATION TRANSMISSION 

SERVICE REQUESTS......................................................................................................114

32.1 Notice of Need for System Impact Study:...................................................114

32.2 System Impact Study Agreement and Cost Reimbursement: .....................115

32.3 System Impact Study Procedures:...............................................................116

32.4 Facilities Study Procedures: ........................................................................118

32.5 Penalties for Failure to Meet Study Deadlines:...........................................119

33 LOAD SHEDDING AND CURTAILMENTS................................................................119

33.1 Procedures: ..................................................................................................120

33.2 Transmission Constraints: ...........................................................................120

33.3 Cost Responsibility for Relieving Transmission Constraints: ....................121

33.4 Curtailments of Scheduled Deliveries:........................................................121

33.5 Allocation of Curtailments: .........................................................................121

33.6 Load Shedding:............................................................................................122

33.7 System Reliability: ......................................................................................122

34 RATES AND CHARGES ..........................................................................................123

34.1 Monthly Demand Charge: ...........................................................................124
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 8 

34.2 Determination of Network Customer's Monthly Network Load:................124

34.3 Determination of Transmission Provider's Monthly Transmission System 

Load: 124

34.4 Redispatch Charge:......................................................................................124

34.5 Stranded Cost Recovery: .............................................................................125

35 OPERATING ARRANGEMENTS ..............................................................................125

35.1 Operation under The Network Operating Agreement:................................125

35.2 Network Operating Agreement: ..................................................................125

35.3 Network Operating Committee: ..................................................................127

SCHEDULE 1 ................................................................................................................128

SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE ....................................128

SCHEDULE 2 ................................................................................................................129

REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION SOURCES 

SERVICE ......................................................................................................................129

SCHEDULE 3 ................................................................................................................131

REGULATION AND FREQUENCY RESPONSE SERVICE...............................................131

SCHEDULE 4 ................................................................................................................132

ENERGY IMBALANCE SERVICE..................................................................................132

SCHEDULE 5 ................................................................................................................134

OPERATING RESERVE - SPINNING RESERVE SERVICE.............................................134

SCHEDULE 6 ................................................................................................................135

OPERATING RESERVE - SUPPLEMENTAL RESERVE SERVICE ..................................135

SCHEDULE 7 ................................................................................................................136

LONG-TERM FIRM AND SHORT-TERM FIRM POINT-TO-POINT..............................136

SCHEDULE 8 ................................................................................................................138

NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE...........................................138

SCHEDULE 9 ................................................................................................................140

GENERATOR IMBALANCE SERVICE...........................................................................140

ATTACHMENT A ........................................................................................................143

FORM OF SERVICE AGREEMENT FOR FIRM POINT-TO-POINT TRANSMISSION 

SERVICE ......................................................................................................................143
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 9 

ATTACHMENT A-1.....................................................................................................147

FORM OF SERVICE AGREEMENT FOR THE RESALE, REASSIGNMENT OR TRANSFER 

OF LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE........................147

ATTACHMENT B ........................................................................................................151

FORM OF SERVICE AGREEMENT FOR NON-FIRM POINT-TO-POINT TRANSMISSION 

SERVICE ......................................................................................................................151

ATTACHMENT C ........................................................................................................153

METHODOLOGY TO ASSESS AVAILABLE TRANSFER CAPABILITY..........................153

ATTACHMENT D ........................................................................................................155

METHODOLOGY FOR COMPLETING A SYSTEM IMPACT STUDY ..............................155

ATTACHMENT E ........................................................................................................156

INDEX OF POINT-TO-POINT TRANSMISSION SERVICE CUSTOMERS.......................156

ATTACHMENT F.........................................................................................................157

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION SERVICE...157

ATTACHMENT G........................................................................................................158

NETWORK OPERATING AGREEMENT........................................................................158

ATTACHMENT H........................................................................................................159

ANNUAL TRANSMISSION REVENUE REQUIREMENT FOR NETWORK INTEGRATION 

TRANSMISSION SERVICE ............................................................................................159

ATTACHMENT I..........................................................................................................160

INDEX OF NETWORK INTEGRATION TRANSMISSION SERVICE CUSTOMERS..........160

ATTACHMENT J .........................................................................................................161

PROCEDURES FOR ADDRESSING PARALLEL FLOWS ................................................161

ATTACHMENT K........................................................................................................162

TRANSMISSION PLANNING PROCESS.........................................................................162

ATTACHMENT L ........................................................................................................164

CREDITWORTHINESS PROCEDURES ..........................................................................164
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 10 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 11 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 12 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 13 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 14 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 15 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 16 

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-ToPoint 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 17 

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-To-Point Transmission Service is available on a stand-alone basis for 

periods ranging from one hour to one month. 

1.29 Non-Firm Sale: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 18 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 19 

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 

Point-To-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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 20 

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 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 21 

(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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 22 

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-ToPoint 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: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 23 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 24 

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 transmissiononly, 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 25 

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 - Spinning, (iv) Operating Reserve - 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 26 

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 self-supply. 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 27 

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: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 28 

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 § 37 of the Commission's 

regulations (Open Access Same-Time Information System and Standards of 

Conduct for Public Utilities) and 18 C.F.R. § 38 of the Commission’s regulations 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 29 

(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 website 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 website an electronic link to 

the NAESB website where any rules, standards and practices that are protected by 

copyright may be obtained. The Transmission Provider shall also make available 

on its public website 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 30 

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 tax-exempt 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 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 
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Original Sheet No. 31 

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 
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Original Sheet No. 32 

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 
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Original Sheet No. 33 

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 C.F.R.  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. 
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Original Sheet No. 34 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 35 

 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 
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Original Sheet No. 36 

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 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 37 

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 
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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 
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Original Sheet No. 39 

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 
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Original Sheet No. 40 

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-To-Point 

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-To-Point 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

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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 ShortTerm 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 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 42 

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-To-Point 

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, pre-confirmation 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 
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Original Sheet No. 43 

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 Third-Party 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 Point-To-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-
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Term Firm Point-To-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 
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Original Sheet No. 45 

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 
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Original Sheet No. 46 

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 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 
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Original Sheet No. 47 

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 
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Original Sheet No. 48 

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 LongTerm 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-To-Point Service Agreement for LongTerm 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 
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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-To-Point Transmission Service: 

Schedules for the Transmission Customer's Firm Point-To-Point Transmission 

Service must be submitted to the Transmission Provider no later than 10:00 

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 
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Original Sheet No. 50 

commencement of such service. Schedules submitted after 10:00 a.m. will be 

accommodated, if practicable. Hour-to-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 
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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 NonFirm 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 
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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 Non-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: (a) immediately for hourly 

Non-Firm Point-To-Point Transmission Service after notification by the 

Transmission Provider; and, (b) within 24 hours (or earlier if necessary to 

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 Point-To-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 [insert date sixty (60) days after publication in Federal 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 53 

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 Non-Firm Point-To-Point Transmission 

Service to make Third-Party 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 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. 

14.5 Classification of Non-Firm Point-To-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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 54 

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 non-firm 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 Point-To-Point Transmission Service: 

Schedules for Non-Firm Point-To-Point Transmission Service must be 

submitted to the Transmission Provider no later than 2:00 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 2:00 p.m. will be accommodated, if 

practicable. Hour-to-hour 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 55 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 56 

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, Non-Firm 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-ToPoint 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-to-Point 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 57 

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-ToPoint 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 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-To-Point 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 58 

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: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 59 

(a) If the Transmission Provider determines that it cannot 

accommodate a Completed Application for Firm Point-To-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 Point-To-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, 
(Name of Transmission Provider) Open Access Transmission Tariff 

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(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 self-provided 

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 Point-To-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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 61 

(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 
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Original Sheet No. 62 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 63 

the Transmission Provider’s planning process established in 

Attachment K; and 

(f) The Transmission Customer has executed a Point-To-Point 

Service 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 64 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 65 

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; 
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Original Sheet No. 66 

(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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 67 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 68 

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 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 69 

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 non-discriminatory 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 
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Original Sheet No. 70 

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 
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Original Sheet No. 71 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 72 

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-To-Point Transmission Service: 

Requests for monthly service shall be submitted no earlier than sixty (60) days
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Original Sheet No. 73 

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 2:00 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 non-discriminatory 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 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 
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Original Sheet No. 74 

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 
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Original Sheet No. 75 

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 
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Original Sheet No. 76 

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 
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Original Sheet No. 77 

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. 
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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 
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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 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 
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Original Sheet No. 80 

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 PointTo-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 
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Original Sheet No. 81 

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. 
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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 
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Original Sheet No. 83 

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 nonAffiliates’ 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 
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Original Sheet No. 84 

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 Point-To-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 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 
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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. 
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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 
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Original Sheet No. 87 

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 Point-To-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 non-firm only, on an as-available basis and will not 

displace any firm or non-firm service reserved or scheduled by 

third-parties under the Tariff or by the Transmission Provider on 
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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 

Point-To-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 nonfirm basis shall not require the filing of an Application for NonFirm Point-To-Point 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 
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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 

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 
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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: 
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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 
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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 Point-To-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 
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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 
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allows Network Customers to efficiently and economically utilize their 

Network Resources (as well as other non-designated 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 

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 
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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 as-available 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. 
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Original Sheet No. 96 

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 Point-To-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 
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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 
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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 
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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: 

• 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 
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− 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 
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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 
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• 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 
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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 noninterruptible 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 
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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 
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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 non-designated third party load or otherwise cannot be 

called upon to meet the Network Customer's Network Load on a noninterruptible 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. 

30.2 Designation of New Network Resources: 
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Original Sheet No. 106 

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 noninterruptible 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 
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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 
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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 
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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-to-Point 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, 

non-discriminatory basis between all Network Customers, and the 
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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) 
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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 

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 
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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 
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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.
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Original Sheet No. 114 

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 non-discriminatory 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: 
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Original Sheet No. 115 

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 
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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 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: 
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Original Sheet No. 117 

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 
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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 
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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 
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Original Sheet No. 120 

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 
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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 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: 
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Original Sheet No. 122 

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 
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Original Sheet No. 123 

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 
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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 Point-To-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: 
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Original Sheet No. 125 

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 
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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 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 C.F.R. § 39.1, (ii) satisfy its Control Area requirements, 

including all necessary Ancillary Services, by contracting with the 
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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. 
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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. 
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Original Sheet No. 129 

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 non-generation 

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 
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Original Sheet No. 130 

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. 
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Original Sheet No. 131 

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. 
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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 non-generation 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 
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Original Sheet No. 133 

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 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. 
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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 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 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. 
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Original Sheet No. 135 

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. 
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Original Sheet No. 136 

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 $ /KW of Reserved 

Capacity per year. 

2) Monthly delivery: $ /KW of Reserved Capacity per month. 

3) Weekly delivery: $ /KW of Reserved Capacity per week. 

4) Daily delivery: $ /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) 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 137 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 138 

SCHEDULE 8 

Non-Firm Point-To-Point Transmission Service 

 The Transmission Customer shall compensate the Transmission Provider for NonFirm Point-To-Point Transmission Service up to the sum of the applicable charges set 

forth below: 

1) Monthly delivery: $ /KW of Reserved Capacity per month. 

2) Weekly delivery: $ /KW of Reserved Capacity per week. 

3) Daily delivery: $ /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 $ /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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 139 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 140 

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 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 141 

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. 

1764. 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 142 

redispatch costs), incremental operation and maintenance costs, and purchased and 

interchange power costs and taxes, as applicable. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 143 

 Page 1 of 4 

ATTACHMENT A 

Form Of Service Agreement For 

Firm Point-To-Point Transmission Service 

1.0 This Service Agreement, dated as of _______________, is entered into, by and 

between _____________ (the Transmission Provider), and ____________ 

("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-To-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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 144 

 Page 2 of 4 

Transmission Provider:

_____________________________________ 

_____________________________________ 

_____________________________________ 

Transmission Customer:

_____________________________________ 

_____________________________________ 

_____________________________________ 

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: ______________________ _______________ ______________ 

 Name Title Date 

Transmission Customer:

By: ______________________ _______________ ______________ 

 Name Title Date 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 145 

 Page 3 of 4 

Specifications For Long-Term Firm Point-To-Point

Transmission Service

1.0 Term of Transaction: __________________________________ 

 Start Date: ___________________________________________ 

 Termination Date: _____________________________________ 

2.0 Description of capacity and energy to be transmitted by Transmission Provider 

including the electric Control Area in which the transaction originates. 

 _______________________________________________________ 

3.0 Point(s) of Receipt:___________________________________ 

 Delivering Party:_______________________________________ 

4.0 Point(s) of Delivery:__________________________________ 

 Receiving Party:______________________________________ 

5.0 Maximum amount of capacity and energy to be transmitted 

 (Reserved Capacity):___________________________________ 

6.0 Designation of party(ies) subject to reciprocal service 

obligation:_________________________________________________________

__________________________________________________________________

__________________________________________________________________

__________________________________________________________________ 

7.0 Name(s) of any Intervening Systems providing transmission 

service:____________________________________________________________

__________________________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 146 

 Page 4 of 4 

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:________________________________ 

 __________________________________________________ 

8.2 System Impact and/or Facilities Study Charge(s): 

 __________________________________________________ 

 __________________________________________________ 

8.3 Direct Assignment Facilities Charge:____________________ 

 __________________________________________________ 

8.4 Ancillary Services Charges: ______________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 147 

 Page 1 of 4 

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 _______________, is entered into, by and 

between ____________ (the Transmission Provider), and ____________ (the 

Assignee). 

2.0 The Assignee has been determined by the Transmission Provider to be an Eligible 

Customer under the Tariff pursuant to which 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 148 

 Page 2 of 4 

Transmission Provider: 

______________________________ 

______________________________ 

______________________________ 

Assignee: 

______________________________ 

______________________________ 

______________________________ 

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:____________________________ ______________________ _______________ 

 Name Title Date 

Assignee: 

By:____________________________ ______________________ _______________ 

 Name Title Date 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 149 

 Page 3 of 4 

Specifications For The Resale, Reassignment Or Transfer of 

Long-Term Firm Point-To-Point Transmission Service

1.0 Term of Transaction: ___________________________________ 

 Start Date: ___________________________________________ 

 Termination Date: _____________________________________ 

2.0 Description of capacity and energy to be transmitted by Transmission Provider 

including the electric Control Area in which the transaction originates. 

 _______________________________________________________ 

3.0 Point(s) of Receipt:___________________________________ 

 Delivering Party:_______________________________________ 

4.0 Point(s) of Delivery:__________________________________ 

 Receiving Party:______________________________________ 

5.0 Maximum amount of reassigned capacity: __________________ 

6.0 Designation of party(ies) subject to reciprocal service 

obligation:_________________________________________________________

__________________________________________________________________

__________________________________________________________________

__________________________________________________________________ 

7.0 Name(s) of any Intervening Systems providing transmission 

service:____________________________________________________________

__________________________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 150 

 Page 4 of 4 

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:________________________________ 

 __________________________________________________ 

8.2 System Impact and/or Facilities Study Charge(s): 

 __________________________________________________ 

 __________________________________________________ 

8.3 Direct Assignment Facilities Charge:____________________ 

 __________________________________________________ 

8.4 Ancillary Services Charges: ______________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

9.0 Name of Reseller of the reassigned transmission capacity: 

___________________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 151 

ATTACHMENT B 

Form Of Service Agreement For Non-Firm Point-To-Point 

Transmission Service 

1.0 This Service Agreement, dated as of _______________, is entered into, by and 

between _______________ (the Transmission Provider), and ____________ 

(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 Point-To-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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 152 

Transmission Provider:

____________________________________ 

____________________________________ 

____________________________________ 

Transmission Customer:

_____________________________________ 

_____________________________________ 

_____________________________________ 

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: ______________________ _______________ ______________ 

 Name Title Date 

Transmission Customer: 

By: ______________________ _______________ ______________ 

 Name Title Date 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 153 

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 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 154 

(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 loadserving 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 155 

ATTACHMENT D 

Methodology for Completing a System Impact Study 

To be filed by the Transmission Provider 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 156 

ATTACHMENT E 

Index Of Point-To-Point Transmission Service Customers 

 Date of 

 Customer Service Agreement 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 157 

ATTACHMENT F 

Service Agreement For 

Network Integration Transmission Service 

To be filed by the Transmission Provider 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 158 

ATTACHMENT G 

Network Operating Agreement 

 To be filed by the Transmission Provider 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 159 

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 ____________________________. 

2. The amount in (1) shall be effective until amended by the Transmission Provider 

or modified by the Commission. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 160 

ATTACHMENT I 

Index Of Network Integration Transmission Service Customers 

 Date of 

 Customer Service Agreement 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 161 

ATTACHMENT J 

Procedures for Addressing Parallel Flows 

To be filed by the Transmission Provider 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 162 

ATTACHMENT K 

Transmission Planning Process 

The Transmission Provider shall establish a coordinated, open and transparent planning 

process with its Network and Firm Point-to-Point 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 163 

(viii) The relevant cost allocation procedures or principles. 

 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 164 

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 noncreditworthy determination. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 165