UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Parts 35 and 37 

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

Preventing Undue Discrimination and Preference in Transmission Service 

(May 19, 2006) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: The Federal Energy Regulatory Commission is proposing 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. 

DATES: Comments are due [insert date 60 days after publication in the FEDERAL 

REGISTER]. Reply comments are due [insert date 30 days after initial comments]

ADDRESSES: You may submit comments, identified by Docket Nos. RM05-25-000 

and RM05-17-000, by one of the following methods: 

• Agency Web Site: http://www.ferc.gov. Follow the instructions for submitting 

comments via the eFiling link found in the Comment Procedures section of the 

preamble. 
Docket Nos. RM05-25-000 and RM05-17-000 - 2 -

• Mail: Commenters unable to file comments electronically must mail or hand 

deliver an original and 14 copies of their comments to: Federal Energy 

Regulatory Commission, Office of the Secretary, 888 First Street, N.E., 

Washington, D.C., 20426. Please refer to the Comment Procedures section of the 

preamble for additional information on how to file paper comments. 

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 

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 

David Withnell (Legal Information) 

Office of the General Counsel – Energy Markets 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502- 8421 

SUPPLEMENTARY INFORMATION:
 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Preventing Undue Discrimination and 

Preference in Transmission Service 

 

Docket Nos. RM05-25-000 

RM05-17-000 

NOTICE OF PROPOSED RULEMAKING 

(May 19, 2006) 

TABLE OF CONTENTS 

Paragraph Number 

I. INTRODUCTION ....................................................................................................... 1.

II. BACKGROUND ........................................................................................................ 6.

A. Historical Antecedent............................................................................................... 6.

B. Order No. 888 and Subsequent Reforms................................................................ 10.

C. EPAct 2005 and Recent Developments.................................................................. 18.

III. THE NEED FOR REFORM OF ORDER NO. 888............................................. 21.

A. Opportunities for Undue Discrimination Continue to Exist .................................. 21.

B. A Lack of Transparency Undermines Confidence in Open Access and Impedes 

Enforcement of Open Access Requirements .............................................................. 26.

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

the Grid ........................................................................................................................ 31.

D. A Consistent Method of Measuring ATC Has Not Been Established .................. 37.

E. A Number of Transmission Pricing Policies May Impede the Use of the Grid..... 42.

F. EPAct 2005 Emphasized Certain Policies and Priorities for the Commission ...... 46.
Docket Nos. RM05-25-000 and RM05-17-000 - 2 -

IV. SUMMARY, SCOPE AND APPLICABILITY OF THE PROPOSED RULE 50.

A. Summary of Proposed Reforms ............................................................................. 51.

B. Core Elements of Order No. 888 That Are Retained ............................................. 59.

1. Federal/State Jurisdiction .............................................................................. 60.

2. Native Load Protection .................................................................................. 62.

3. The Types of Transmission Services Offered ............................................... 72.

4. Functional Unbundling................................................................................... 80.

C. Applicability of the Proposed Rule ....................................................................... 92.

1. Public Utility Transmission Providers ........................................................... 92.

2. Non-Public Utility Transmission Providers/Reciprocity ............................ 102.

V. PROPOSED MODIFICATIONS OF THE OATT ............................................ 113.

A. Consistency and Transparency of ATC Calculations ......................................... 113.

B. Transmission Planning – Coordinated, Open and Transparent Planning ............ 196.

C. Transmission Pricing ........................................................................................... 220.

1. Imbalances ................................................................................................... 221.

2. Credits for Network Customers .................................................................. 248.

3. Capacity Reassignment ............................................................................... 260.

4. “Operational” Penalties ............................................................................... 277.

a. Unauthorized Use Penalties ..................................................................... 277.

b. How Transmission Providers Should Pay Operational Penalties............ 281.

5. “Higher of” Pricing Policy ........................................................................... 284.

D. Non-Rate Terms and Conditions.......................................................................... 287.

1. Potential Modifications to Long-Term Firm Point-to-Point Service .......... 288.

2. Hourly Firm Service..................................................................................... 333.

3. Rollover Rights ............................................................................................ 348.

4. Modification of Receipt or Delivery Points................................................. 361.

5. Acquisition of Transmission Service .......................................................... 373.

a. Processing of Service Requests ............................................................... 373.

b. Queue Processing Business Practices...................................................... 390.
Docket Nos. RM05-25-000 and RM05-17-000 - 3 -

c. Reservation Priority ................................................................................. 394.

6. Designation of Network Resources.............................................................. 402.

a. Qualification as a Network Resource ...................................................... 402.

b. Documentation for Network Resources................................................... 410.

c. Undesignation of Network Resources ..................................................... 416.

7. Clarifications Related to Network Service................................................... 424.

8. Transmission Curtailments .......................................................................... 435.

9. Standardization of Rules and Practices........................................................ 444.

10. OATT Definitions ..................................................................................... 457.

E. Enforcement ......................................................................................................... 464.

1. General Policy ............................................................................................. 464.

a. Compliance Review Regime ................................................................... 464.

b. Use of Independent Third Party Audits .................................................. 467.

2. Civil Penalties .............................................................................................. 471.

a. Background .............................................................................................. 471.

b. Whether Civil Penalties Should Be Specified in the OATT .................. 474.

c. Whether Transmission Providers Should Be Subject to Revocation of Their 

Market-Based Rates for OATT Violations. ................................................. 478.

d. Whether Certain OATT Violations Should Be Considered Market 

Manipulation under the Market Behavior Rules and Section 1283 of EPAct 

2005. ............................................................................................................ 481.

VI. INFORMATION COLLECTION STATEMENT............................................. 486.

VII. ENVIRONMENTAL ANALYSIS ..................................................................... 491.

VIII. REGULATORY FLEXIBILITY ACT ANALYSIS ...................................... 492.

IX. COMMENT PROCEDURES .............................................................................. 493.

X. DOCUMENT AVAILABILITY............................................................................ 497.

APPENDIX A: Commenter Acronyms 

APPENDIX B: Pro Forma Open Access Transmission Tariff 
 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Preventing Undue Discrimination and 

Preference in Transmission Service 

Docket Nos. RM05-25-000 

RM05-17-000 

NOTICE OF PROPOSED RULEMAKING 

(May 19, 2006) 

I. Introduction 

1. Ten years have passed since the Commission issued its landmark Order No. 888.1

 

Named after our new headquarters in Washington, D.C., Order No. 888 sought to 

eradicate undue discrimination in the provision of transmission service in interstate 

commerce. It did so by requiring that each public utility that owns, operates, or controls 

facilities used for transmission in interstate commerce offer unbundled transmission 

service pursuant to a standard Open Access Transmission Tariff (pro forma OATT) and 

 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. RM05-25-000 and RM05-17-000 - 2 – 

separate its transmission and merchant generation functions pursuant to a companion 

order issued that same day, Order No. 889.2

 These remedies reduced barriers to entry, 

led to greater competition in bulk power markets and provided the foundation for 

subsequent regulatory reforms at both the federal and state level. 

2. 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. 2000,3

 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.4 

The Commission in Order No. 2000 thus encouraged utilities to voluntarily join 

independent regional transmission organizations (RTOs) that would operate their 

transmission facilities on a non-discriminatory basis and administer the OATT. The 

 2

 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). 

3

 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). 

4

 Order No. 2000 at 31,015. 
Docket Nos. RM05-25-000 and RM05-17-000 - 3 – 

Commission based Order No. 2003 on a similar finding, explaining that the 

interconnection process includes opportunities for undue discrimination that may lead to 

delays that benefit generation-owning transmission utilities and undermine competition.5 

While many regions of the country now have independent grid operators, not all do, and 

changes to the pro forma OATT are necessary to reduce the opportunity for transmission 

providers to engage in undue discrimination. In the past ten years new investment has 

faltered and many regions now experience chronic transmission congestion and 

inadequate infrastructure. Congress, through the Energy Policy Act of 2005 (EPAct 

2005),6

 recognized this problem and provided the Commission not only new tools to 

encourage infrastructure but also made clear that the Commission should use its existing 

authority to ensure an adequate infrastructure to support a vibrant economy. 

3. The reforms we propose today are intended to address deficiencies in the pro 

forma OATT that have become apparent since 1996 and to facilitate improved planning 

and operation of transmission facilities. We summarize these reforms in Part IV.A 

below, but note the major focus of this reform effort here. As a general matter, 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 

 5

 See Order No. 2003 at P 11-12. 

6

 Pub. L. No. 109-58, 119 Stat. 594 (to be codified in scattered titles of the 

U.S.C.). 
Docket Nos. RM05-25-000 and RM05-17-000 - 4 – 

structures. We propose to achieve this goal by increasing the clarity and transparency of 

the rules applicable to the planning and use of the transmission system and by addressing 

ambiguities and the lack of sufficient detail in several important areas of the pro forma

OATT. The lack of specificity in the pro forma OATT creates opportunities for undue 

discrimination as well as making the undue discrimination that does occur more difficult 

to detect. First, we propose to improve transparency and consistency in several critical 

areas, such as the calculation of available transfer capability (ATC).7

 We propose to 

direct public utilities, under the auspices of the North American Electric Reliability 

Council (NERC) and the North American Energy Standards Board (NAESB), to provide 

for greater consistency in ATC calculation. By reducing unnecessarily broad discretion 

in this and other areas, we will reduce the ability of transmission providers to unduly 

discriminate and provide them greater certainty to facilitate compliance with our 

regulations. Second, we propose 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 load-serving entities. The pro 

forma OATT contains only minimal requirements regarding transmission planning, 

 7

 We note that 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 

is proposing to revise the pro forma OATT to adopt the term "Available Transfer 

Capability." 
Docket Nos. RM05-25-000 and RM05-17-000 - 5 – 

which have proven to be inadequate as the Nation faces inadequate transmission 

investment in many areas. We propose to require public utilities to engage in an open 

and transparent planning process at both the local and regional levels. Third, we propose 

to remedy certain portions of the pro forma OATT that may have permitted utilities to 

discriminate against new merchant generation, including intermittent generation. For 

example, we propose to modify the energy imbalance provisions of the pro forma OATT 

and adopt certain other tariff modifications. Fourth, we 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 our ability to detect any remaining incidents of undue discrimination. Finally, 

we provide for reform and greater clarity in areas that have generated recurring disputes 

over the past 10 years, such as rollover rights, “redirects,” and generation redispatch. 

4. Although the reforms being proposed in these areas are significant, we wish to 

underscore that we propose to maintain many of the core elements of Order No. 888. For 

example, we are retaining the comparability requirement under which each public utility 

must treat third parties in a manner comparable to its service to bundled customers. We 

are retaining the basic nature of the services being offered – network service and point-topoint service. We are retaining the protection of native load customers embodied in 

Order No. 888, consistent with EPAct 2005’s new requirement that load-serving entities 
Docket Nos. RM05-25-000 and RM05-17-000 - 6 – 

be provided transmission rights to meet their service obligations.8

 We are retaining our 

decision to exercise jurisdiction over unbundled transmission service, but not 

transmission service provided as part of a bundled retail service. We are retaining the use 

of functional unbundling to address undue discrimination, rather than requiring corporate 

unbundling. We are retaining 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 imposing any particular market structure on the industry. 

5. In proposing to reform Order No. 888, we have relied heavily on the comments 

received in response to our notices of inquiry in the above-captioned dockets.9 We 

appreciate the time and thoughtfulness of all sectors of the industry in preparing 

comments on these notices of inquiry. We have found them very informative and useful 

and this Notice of Proposed Rulemaking (NOPR) incorporates many of the commenters' 

suggestions. We invite further comments on this NOPR. We also are scheduling 

technical conferences to more fully address the topics of ATC calculation and 

transmission planning. 

 8

 EPAct 2005 sec. 1233 (to be codified at section 217(b)(4) of the FPA, 16 U.S.C. 

824q). 

9

 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. RM05-25-000 and RM05-17-000 - 7 – 

II. Background 

A. Historical Antecedent

6. 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 other 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 due primarily to the cost and 

technological limitations on the distance over which electricity could be transmitted. 

7. 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),10 which was 

designed to lessen dependence on foreign fossil fuels by encouraging the development of 

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

30, 42, and 43 (2000)). 
Docket Nos. RM05-25-000 and RM05-17-000 - 8 – 

alternative generation sources and imposing a mandatory purchase obligation on utilities 

for generation from such sources. PURPA also enabled the Commission to order 

wheeling of electricity under limited circumstances.11 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 

 11 Section 211 of the FPA, 16 U.S.C. 824j (2000). 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 Company, 

839 F. Supp. 1563 (M.D. Fla. 1993). 
Docket Nos. RM05-25-000 and RM05-17-000 - 9 – 

provide open access to third parties and favored their own generation if and when they 

provided transmission access to third parties, access to cheaper, more efficient generation 

sources remained limited. 

8. 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 possessed.12 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 

 12 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. RM05-25-000 and RM05-17-000 - 10 – 

mitigate their market power to meet the Commission’s conditions, public utilities seeking 

Commission authorization for blanket approval of market-based rates for generation 

services under section 205 of the FPA filed "open access" transmission tariffs of general 

applicability.13 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. 

9. 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 

 13 See Order No. 888 at 31,644 n.52. 
Docket Nos. RM05-25-000 and RM05-17-000 - 11 – 

of the Energy Policy Act of 1992 (EPAct 1992).14 EPAct 1992 reduced regulatory 

barriers to entry by creating a class of "Exempt Wholesale Generators" that were exempt 

from the requirements of the Public Utility Holding Company Act of 1935.15 EPAct 

1992 also expanded the Commission's authority to approve applications for transmission 

services under sections 211 and 212 of the FPA. 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

10. In April 1996, as part of its statutory obligation under sections 205 and 206 of the 

FPA to remedy undue discrimination, the Commission adopted Order No. 888 

prohibiting public utilities from using their monopoly power over transmission to unduly 

discriminate against others. In that order, the Commission required all public utilities 

that own, control or operate facilities used for transmitting electric energy in interstate 

commerce to file open access non-discriminatory transmission tariffs that contained 

minimum terms and conditions of non-discriminatory service. It also obligated such 

 14 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 (2000)). 

15 15 U.S.C. 79a (2000), 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). 
Docket Nos. RM05-25-000 and RM05-17-000 - 12 – 

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.16 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).17 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 and 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 which conditions the use by non-public utilities of public utilities’ open 

access services on an agreement to offer open access services in return. 

 16 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 retain ownership over both functions. See infra 

Part IV.B.4. 

17 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 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. RM05-25-000 and RM05-17-000 - 13 – 

11. 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 “have the potential to provide significant 

benefits (e.g., to help provide regional efficiencies, to facilitate economically efficient 

pricing, and, especially in the context of power pools, to remedy undue discrimination 

and mitigate market power) and will further our goal of achieving a workably 

competitive market.”18 While the Commission declined to mandate ISOs, it set forth 

eleven principles for assessing ISO proposals submitted to the Commission.19 

12. Order No. 888 also clarified the Commission's interpretation of the federal/state 

jurisdictional boundaries over transmission and local distribution. While it 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.20 

 18 Order No. 888 at 31,655. 

19 Id. at 31,730-32. 

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

13. The same day it issued Order No. 888, the Commission issued a companion order, 

Order No. 889, addressing both 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. 

14. Among the information required to be posted by Order No. 889 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.”21 Because formal methods did not then 

exist to calculate ATC and total transfer capability (TTC), the Commission encouraged 

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

industry efforts to develop consistent methods for calculating ATC and TTC.22 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.23 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.”24 

15. 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.25 This state restructuring activity spurred 

significant changes at the wholesale level as well by encouraging or requiring the 

divestiture of generation plants by traditional electric utilities and the development of 

ISOs that could manage short-term energy markets necessary to support retail access. At 

the same time, there was a significant increase in the number of mergers between 

traditional electric utilities and between electric utilities and gas pipeline companies, and 

large increases in the number of power marketers and independent generation facility 

developers entering the marketplace. Trade in bulk power markets increased 

 22 Id. at 31,607. 

23 Id.

24 Id. 

25 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. RM05-25-000 and RM05-17-000 - 16 – 

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. 

16. In the wake of these changes, in December 1999, the Commission adopted Order 

No. 2000.26 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.27 

The rulemaking also recognized that Order No. 888 did not address the regional nature of 

the grid, including the treatment of parallel flows, pancaked rates, and congestion 

management. Thus, the Commission encouraged the creation of RTOs to address 

important operational and reliability issues and eliminate any residual discrimination in 

transmission services that can occur when the operation of the transmission system 

remains in the control of a vertically integrated utility. The Commission found that 

RTOs would increase the efficiency of wholesale markets by eliminating pancaked rates, 

internalizing parallel flow, managing congestion efficiently and operating markets for 

energy, capacity and ancillary services. The Commission established an open, 

collaborative process that relied on voluntary regional participation to design RTOs 

tailored to the specific needs of each region. The Commission noted, however, that “[i]f 

 26 See supra note 3. 

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

the industry fails to form RTOs under this approach, the Commission will reconsider 

what further regulatory steps are in the public interest.”28

17. Following Order No. 2000, RTOs were approved in several regions of the country 

including the Northeast (PJM Interconnection, Inc.; ISO New England), 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

18. EPAct 2005,29 enacted on August 8, 2005, added a number of new authorities and 

priorities for the Commission and emphasized certain of its existing obligations. 

Specifically, EPAct 2005 recognized the importance of adequate transmission 

infrastructure development and its role in facilitating the development of competitive 

wholesale markets. For example, Congress required the Commission to adopt a rule 

 28 Id. at 30,993. 

29 See supra note 6. 
Docket Nos. RM05-25-000 and RM05-17-000 - 18 – 

establishing incentive ratemaking for transmission infrastructure to help promote 

reliability and reduce congestion.30 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.”31 Congress also gave the Commission certain “backstop” transmission siting 

authority, and authorized the creation of interstate compacts establishing transmission 

siting agencies.32 EPAct 2005 also authorized the Commission to require unregulated 

transmitting utilities (except for certain small entities) to provide access to their 

transmission facilities on a comparable basis.33 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 

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

824s). 

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

16 U.S.C. 824q). 

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

824p). 

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

824j-1). 
Docket Nos. RM05-25-000 and RM05-17-000 - 19 – 

region.34 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.35 Finally, Congress emphasized compliance with the 

Commission’s regulations, increasing the civil and criminal penalties for violations of 

Commission-administered statutes and regulations.36 

19. Recognizing the need for reform of Order No. 888 in light of these developments 

and those described in the next section, the Commission issued an NOI in September 

2005 seeking comments on the reforms needed to the Order No. 888 pro forma OATT to 

prevent undue discrimination and preference in the provision of transmission services. In 

the NOI, the Commission expressed its preliminary view that reforms to the pro forma

 34 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 

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.” EPAct 2005 sec. 1234 (b). 

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

824t). 

36 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). 
Docket Nos. RM05-25-000 and RM05-17-000 - 20 – 

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. 

20. 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, 

our experience in implementing Order No. 888, and the changes in the industry since we 

adopted it, we conclude that reform of the pro forma OATT is necessary, for the reasons 

we discuss next. 

III. The Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination Continue to Exist

21. In Order No. 2000, the Commission found that “opportunities for undue 

discrimination continue to exist that may not be remedied adequately by [the] functional 

unbundling [remedy of Order No. 888].”37 The Commission made a similar finding in 

Order No. 2003, holding that opportunities for undue discrimination continue to exist in 

areas where the pro forma OATT leaves transmission providers with substantial 

 37 Order No. 2000 at 31,105. 
Docket Nos. RM05-25-000 and RM05-17-000 - 21 – 

discretion.38 The Commission has a responsibility under section 206 of the FPA to 

remedy undue discrimination.39 Our action today proposes to fulfill that responsibility by 

proposing reforms to the pro forma OATT that will address remaining opportunities for 

undue discrimination. 

22. As the Commission noted in Order No. 888, it is in the economic self-interest of 

transmission monopolists, particularly those with high-cost generation assets, to deny 

transmission or to offer transmission on a basis that is inferior to that which they provide 

 38 Order No. 2003 at P 11-12. 

39 In Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir. 1987), 

(AGD), the court concluded that, like the Natural Gas Act, the FPA “fairly bristles” with 

concern over undue discrimination. Based on AGD, the Commission determined in 

Order No. 888 that: 

The Commission has a mandate under sections 205 and 206 

of the FPA to ensure that, with respect to any transmission in 

interstate commerce or any sale of electric energy for resale 

in interstate commerce by a public utility, no person is subject 

to any undue prejudice or disadvantage. We must determine 

whether any rule, regulation, practice or contract affecting 

rates for such transmission or sale for resale is unduly 

discriminatory or preferential, and must prevent those 

contracts and practices that do not meet this standard. . . . 

AGD demonstrates that our remedial power is very broad and 

includes the ability to order industry-wide non-discriminatory 

open access as a remedy for undue discrimination. 

Order No. 888 at 31,669. 
Docket Nos. RM05-25-000 and RM05-17-000 - 22 – 

themselves.40 Such an incentive can lead to unduly discriminatory behavior against third 

parties, particularly if public utilities have unnecessarily broad discretion in the 

application of their tariffs. This discretion also can create problems for transmission 

providers seeking to comply with our regulations in good faith because so many issues 

are left for their interpretation, thereby increasing the possibility of disputes with 

transmission customers and enforcement actions by the Commission.41 Transmission 

customers also have found ways to use the tariffs to their own advantage, particularly in 

the scheduling and queuing processes.42 Finally, tariff provisions have been modified in 

numerous ways on a company-by-company basis, leading to uncertainties within the 

industry as to the proper interpretation of those provisions and to unnecessarily 

inconsistent treatment of transmission customers across public utilities. 

23. Commenters suggest that enhanced clarity and consistency in the pro forma OATT 

would go a long way toward eliminating the opportunities for undue discrimination and 

 40 Id. at 31,682. 

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

42 See, e.g., Potomac Economics, Ltd., 2004 State of the Market Report: Midwest 

ISO at 30-31, 34-35 (Jun. 2005) (explaining that the queuing process, by giving 

customers the opportunity to submit multiple requests for service, provides a low or nocost 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), 

http://www.midwestmarket.org/publish/Document/2b8a32_103ef711180_-

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

ttachment. 
Docket Nos. RM05-25-000 and RM05-17-000 - 23 – 

the perception that it is occurring.43 Calpine notes that undue discrimination is most 

likely to occur when the transmission provider retains discretion to implement an OATT 

provision in a manner that favors its affiliated generation. APPA asserts that the success 

of the OATT regime depends on public utilities’ ability to faithfully implement the 

OATT’s provisions. Large transmission providers share this view to some degree. 

Entergy notes that a lack of clarity is at the heart of many disputes involving the OATT, 

and urges the Commission to improve the OATT in a manner that will minimize the 

potential for future violations. Duke posits that tariff terms and conditions that are 

susceptible to multiple interpretations present opportunities for discrimination and/or the 

perception thereof. Progress Energy agrees that several OATT provisions can be 

interpreted differently, leaving room for disagreement as to their meaning. 

24. Perhaps the most obvious deficiency in this regard is ATC calculation. In Order 

Nos. 888 and 889, the Commission declined to require a specific methodology for ATC 

calculation. As a result, there are few clear rules respecting ATC calculation, and 

transmission providers, therefore, retain unnecessarily broad discretion in this area. On 

systems where transmission capacity is congested, this lack of consistency, coupled with 

 43 E.g., Calpine, Duke, and MidAmerican. (A list of commenter acronyms may be 

found in Appendix A). As the Commission noted in Order No. 2000, “[p]erceptions of 

discrimination are significant impediments to competitive markets. Efficient and 

competitive markets will develop only if market participants have confidence that the 

system is administered fairly.” Order No. 2000 at 31,017. 
Docket Nos. RM05-25-000 and RM05-17-000 - 24 – 

a lack of transparency, has led to recurring disputes over whether the transmission 

provider is exercising its discretion to discriminate against its competitors. 

25. There is a similar lack of clarity in the transmission provider’s planning 

obligations. Order No. 888 included a general obligation on the part of the transmission 

providers to plan on a comparable basis (i.e., comparable to the manner in which it would 

plan for its own needs) to serve network loads and to construct new facilities as necessary 

to respond to requests for firm service from point-to-point customers. However, there 

were no clear guidelines with respect to whether transmission customers should be 

included in the planning process, what standards and criteria should be used in system 

planning, and whether the planning process should identify potential economic upgrades 

that could benefit a wide range of customers, as opposed to responding only to customerspecific requests. Here too, this lack of clarity has led to significant disputes over 

whether transmission providers are planning on a nondiscriminatory basis or are favoring 

service to their own loads. 

B. A Lack of Transparency Undermines Confidence in Open Access and 

Impedes Enforcement of Open Access Requirements 

26. A major focus of comments on the NOI is that increased transparency would aid 

transmission customers in their participation in the wholesale market.44 Constellation 

explains that the transmission provider’s unique position as the owner and operator of the 

 44 E.g., LG&E, MidAmerican, Midwest SATs, TDU Systems, and Williams. 
Docket Nos. RM05-25-000 and RM05-17-000 - 25 – 

transmission system and often the majority of the generation assets in its control area 

gives it better information than its transmission customers. Moreover, the transmission 

provider, Constellation argues, has financial incentives to use the system differently, and 

more efficiently, to serve its own loads than to serve its other customers under the pro 

forma OATT. TDU Systems urges the Commission to ensure that transmission providers 

make their actions under the OATT completely transparent on a timely basis to all 

transmission customers. NARUC posits that enhanced reporting requirements, if 

sufficiently targeted, would facilitate greater transparency in transmission activities. 

Alberta Intervenors states that the current pro forma OATT provides transmission 

customers with only a narrow glimpse of how the system is being operated. For example, 

Bonneville notes that many terms and conditions of native load service are not 

transparent to OATT transmission customers.45 EEI also states that greater transparency, 

such as with respect to ATC calculation, can increase confidence in open access and 

potentially reduce claims of undue discrimination. 

27. Calpine argues that undue discrimination is difficult to detect given the lack of 

access to data, analytical assumptions, and processes used by transmission providers to 

determine transmission access and service. It recommends that the Commission increase 

reporting requirements for denials of transmission service, for congestion management 

 45 Bonneville urges the Commission to require load-serving transmission providers 

to post the same information for bundled retail load that they must post for service to 

network customers. 
Docket Nos. RM05-25-000 and RM05-17-000 - 26 – 

mitigation events, including curtailments and redispatch, and for transmission expansion 

planning decisions. Powerex notes that the Commission already has posting standards, 

and urges the Commission to enforce them and to increase requirements to provide more 

meaningful posting of reliable ATC data, curtailment methodology and results, details 

relating to denials of service, and congestion information. Constellation agrees, urging 

the Commission to require OASIS posting of service metrics, such as all transmission 

requests approved, rejected, confirmed and curtailed. 

28. A common theme in the comments is that the lack of transparency can lead to 

claims of undue discrimination and can make such claims more difficult to resolve.46 

As such, National Grid asserts that greater transparency will allow the Commission and 

transmission system users to understand when a transmission access decision is 

motivated by a legitimate reason rather than an intent to discriminate. If transmission 

customers have more accurate information about the transmission service request 

process, National Grid contends, they also will have more accurate expectations and a 

better understanding of how to expedite the implementation of service. Though NRECA 

agrees that increased transparency will allow the Commission to deter undue 

discrimination and facilitate accountability, it urges the Commission to require not just 

raw data but meaningful, clear and understandable data, in a format that facilitates 

understanding. 

 46 E.g., Ameren, National Grid, and NRECA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 27 – 

29. Commenters urge the Commission to improve the transparency of transmission 

service in a number of areas, particularly the evaluation of ATC and the planning of the 

transmission system.47 Another area often cited as lacking sufficient transparency is the 

processing of transmission service requests and studies. For example, several 

commenters note that system impact studies are often not completed within the tariffprescribed time limits, and that information about that process is not available to 

transmission customers.48 TDU Systems suggests that one way to address the difficulty 

of determining acceptable delays is to require transmission providers to post statistics on 

their OASIS sites providing information as to the length of time it might take to process 

requests for transmission service. Cinergy proposes that adopting such reporting metrics 

could result in an improved quality of service. 

30. We agree that a lack of transparency both increases the potential for undue 

discrimination and makes it more difficult to detect. We believe this lack of sufficient 

transparency is caused in part by inadequate compliance with our existing OASIS 

regulations, and in part by inadequate transparency requirements. Our reforms address 

both elements of the problem in an effort to increase confidence in open access tariffs and 

to facilitate compliance with our regulations and our enforcement of them. 

 47 We discuss these specific aspects of the pro forma OATT below in Parts V.A 

and V.B. 

48 E.g., Constellation, EPSA, Powerex, and Williams. 
Docket Nos. RM05-25-000 and RM05-17-000 - 28 – 

C. Congestion and Inadequate Infrastructure Development Impede 

Customers’ Use of the Grid 

31. The ability and incentive to discriminate increases as the transmission system 

becomes more congested. Vertically integrated utilities do not have an incentive to 

expand the grid to accommodate new entry or to facilitate the dispatch of more efficient 

competitors. Even with the advent of RTOs, transmission infrastructure development has 

not kept pace with the increase in demand for electricity. Transmission capacity is being 

constructed at a much slower rate than the rate of increase in customer demand. Indeed, 

transmission capacity per MW of peak demand declined at an average rate of 2.1 percent 

per year during the period 1992 to 2002.49 Investment for the most recent year available, 

2003, was below 1975 levels,50 and projections suggest that this trend will continue 

through 2012.51 As a result, there has been a significant decrease in transmission 

capacity relative to load in every NERC region.52 EEI estimates that capital spending 

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

(Aug. 2004), available at 

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

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

50 EEI, EEI Survey of Transmission Investment: Historical and Planned Capital 

Expenditures (1999-2008) at 3 (May 2005), available at 

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

b.pdf. 

51 Present Status and Future Prospects at v. 

52 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) Transmission Independence and Investment. 
Docket Nos. RM05-25-000 and RM05-17-000 - 29 – 

must increase by 25 percent, from $4 billion annually to $5 billion annually, to ensure 

system reliability and to accommodate wholesale electric markets.53 The legacy systems 

constructed by vertically integrated utilities prior to the adoption of Order No. 888 

support “only limited amounts of inter-regional power flows and transactions. Thus, 

existing systems cannot fully support all of society’s goals for a modern electric-power 

system.”54 These systems were built to meet the vertically integrated utilities’ retail 

native load obligations, not to support the development of a bulk power market. 

32. Inadequate expansion of the transmission grid has contributed to increasing 

transmission 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: (1) from the Midwest to the MidAtlantic, (2) from the Midwest to the Tennessee Valley Authority (TVA), (3) into and 

within California, (4) from TVA and Southern into Entergy, (5) from Mid-America 

Interconnected Network into Wisconsin-Upper Michigan Systems, and (6) into Florida. 

The existence of these and other constraints affecting transmission systems can result in 

 53 Energy Policy Act of 2005: Hearings before the House Subcommittee on 

Energy and Commerce, 109th Congress, First Sess. (2005) (Prepared statement of 

Thomas R. Kuhn, President of EEI). 

54 Present Status and Future Prospects at v. 
Docket Nos. RM05-25-000 and RM05-17-000 - 30 – 

an increase in the frequency of denials of requests for transmission service, and an 

increase in the frequency of transmission service interruptions and/or curtailments of 

transmission service. While not all congestion needs to be remedied (i.e., if the cost of 

the congestion is less than the cost to relieve it), it is also true that undue discrimination 

and preferential treatment also are much more difficult to detect when the transmission 

grid is constrained, given the lack of transparency in ATC calculations and transmission 

system planning. Increased congestion also presents additional opportunities for undue 

discrimination. As a result, it is more difficult for the Commission to carry out its 

statutory responsibility to ensure that transmission providers provide nondiscriminatory 

open access transmission service. 

33. In recognition of the lack of adequate infrastructure, a broad cross-section of the 

industry supports greater coordination in the planning and investment in transmission 

infrastructure between transmission providers, transmission customers and state 

regulatory agencies. A major focus of comments on our NOI was the need to plan and 

build infrastructure to facilitate regional electricity markets. For example, AEP argues 

that the most important issue faced by public utilities and their customers is not day-today OATT administration but the planning and expansion of the transmission grid. EEI 

likewise asserts that the focus should be on the need to develop energy infrastructure 

necessary to facilitate growth in wholesale electric market transactions. Santa Clara 

acknowledges that lack of needed infrastructure causes the grid to become constrained 

and less reliable, which sometimes provides even stronger incentives for owners to 
Docket Nos. RM05-25-000 and RM05-17-000 - 31 – 

restrict access by others. The Nevada Companies urge the Commission to focus on ways 

Order No. 888 and the pro forma OATT can be revised to eliminate disincentives to the 

construction of additional transmission facilities. Xcel suggests that the Commission 

focus its efforts on ways to encourage investment in new energy infrastructure as a way 

of easing congestion and enabling growth in market transactions. Salt River contends 

that the Commission should increase incentives to participate in long-term regional 

planning processes. Midwest SATs argue that increased access for all transmission 

system users through policies that promote investment in transmission will do more to 

reduce undue discrimination than policies that seek to uncover and penalize such 

discrimination. 

34. Customers also complain that there is often a lack of transparency in utility 

transmission planning processes, which the customers claim typically do not include 

economic system upgrades that would benefit non-affiliate users of the system. 

Customers also note the lack of clarity in the existing planning obligations required of 

transmission providers. They assert that these failures have contributed to the inadequate 

development of the transmission grid. 

35. Order No. 888 contemplated that ISOs would enhance infrastructure development 

through open and regional planning processes, but these efforts have stalled in many 

regions of the country. Even where RTOs have been established, there have been 

concerns that the planning process has not always been sufficiently robust, inclusive or 

transparent to ensure that transmission investment occurs where it is reasonably needed 
Docket Nos. RM05-25-000 and RM05-17-000 - 32 – 

for all users of the grid. For example, in its reply comments, TDU Systems urges the 

Commission to include RTOs in its planning reforms, contending that many RTO 

planning processes are not open to all stakeholders, nor are they collaborative and 

inclusive. Many commenters argue that RTO transmission planning regimes have failed 

to get needed transmission facilities built.55 

36. We conclude that the inadequacy of the existing obligation to conduct joint and 

regional transmission system planning, coupled with the lack of transparency surrounding 

system planning generally, require 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. 

D. A Consistent Method of Measuring ATC Has Not Been Established 

37. Under Order No. 888, each public utility calculates the amount of transfer 

capability on its system that is available for sale to third parties.56 However, Order No. 

888 did not require that the methodology for ATC calculation be standardized across the 

industry, nor did it impose any specific requirements regarding the disclosure of the 

methodologies used by each transmission provider. As a result, there are a variety of 

ATC calculation methodologies in use today. Moreover, there is often very little 

transparency regarding the nature of these calculations, given that many transmission 

 55 E.g., APPA, TDU Systems Reply Comments, and Williams Reply Comments. 

56 Order No. 888 at 31,794 n.610. 
Docket Nos. RM05-25-000 and RM05-17-000 - 33 – 

providers have filed only summary explanations of their ATC methodologies in 

Attachment C to the OATT. As a result, transmission providers retain unnecessarily 

broad discretion in calculating ATC. The 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. This discretion, coupled with the lack of transparency, also 

hampers the detection of undue discrimination and, thereby, undermines the 

Commission's ability to enforce the general requirement in Order No. 888 that 

transmission service be provided on a not unduly discriminatory basis.57

38. The comments on the NOI and the ATC NOI reflect these underlying problems. 

Many market participants complain that there is widespread misinformation regarding the 

actual ATC, which results in missed opportunities for transactions. ATC calculation 

errors often occur. A lack of transparency leaves transmission customers unaware of why 

some transmission requests are granted and others are denied.58 Several ATC inputs, 

such as the capacity benefit margin (CBM) or the transmission reliability margin (TRM), 

can be calculated using overly conservative or otherwise faulty assumptions. 

 57 APPA submitted comments in Docket No. RM05-17-000 arguing that the 

calculation and posting of ATC "sits at the pivot point among reliability, economic 

regulation and wholesale electric commerce." APPA at 5. 

58 See, e.g., EEI at 18 (agreeing that the Commission should require transmission 

providers to make their ATC calculations more transparent). 
Docket Nos. RM05-25-000 and RM05-17-000 - 34 – 

Transmission customers often complain that transmission providers designate 

unreasonably high CBM or TRM levels, which limits the amount of remaining transfer 

capability available for other users of the system. 

39. As a result of these uncertainties, the Commission issued the ATC NOI to address 

the lack of clear and consistent methodologies for calculating ATC. In the ATC NOI, the 

Commission acknowledged that NERC has been working on specific recommendations 

for calculating and coordinating ATC and available flowgate capability (AFC).59 That 

NERC effort culminated in a report and a number of recommendations. The Commission 

asked for comments on those recommendations, as well as comments on whether there 

should be common transmission calculation methodologies among regions. The 

Commission has reviewed those comments as part of this proceeding.60

40. Many commenters support the development of a consistent, industry-wide 

methodology for calculating ATC.61 These commenters maintain that a requirement that 

all transmission providers use the same methodology to determine ATC would not only 

 59 See NERC, Long-Term AFC/ATC Task Force Final Report (2005) (NERC 

Report) at 2, available at 

ftp://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf. 

60 Accordingly, we consolidate Docket No. RM05-17-000 with this proceeding. 

We will distinguish the comments received in the ATC NOI proceeding by the 

designation “ATC NOI Comments.” In addition, we also revise the name of the 

proceeding in Docket No. RM05-17-000 to “Preventing Undue Discrimination and 

Preference in Transmission Service.” 

61 E.g., Alcoa, AWEA, Constellation, Exelon, Occidental, and Renewable Energy. 
Docket Nos. RM05-25-000 and RM05-17-000 - 35 – 

remedy the lack of clarity that surrounds these calculations and reservations, but would 

provide regulatory certainty and assist transmission customers in predicting the outcome 

of transmission service requests. 

41. We agree. Although the industry has sought to pursue greater consistency in ATC 

calculations through existing NERC processes, those efforts to date have been largely 

unsuccessful. 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. We therefore propose below a number of reforms to the process of 

calculating ATC to provide clarity and transparency to users of the grid. 

E. A Number of Transmission Pricing Policies May Impede the Use of the 

Grid

42. Transmission customers often complain about the level and scope of imbalance 

charges that are levied under the pro forma OATT and under individual interconnection 

agreements. 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. 

Customers complain that these 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. Generator 

imbalance charges are levied on generators for deviations between the amount of energy 
Docket Nos. RM05-25-000 and RM05-17-000 - 36 – 

they schedule and the amount they actually deliver to the grid. Generators likewise 

complain that these 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 penalties, which are imposed to provide an incentive 

for generators to schedule accurately, are inappropriate given their lack of control and 

ability to cure deviations. 

43. Transmission providers and customers raise a number of concerns related to the 

pricing of transmission service under Order No. 888, contending that the Commission’s 

pricing policies are in need of reform. For example, under the pro forma OATT, network 

customers can receive a credit toward their transmission charges for new facilities that 

they jointly plan with the transmission provider. Customers contend that this provision 

actually acts as a disincentive for joint planning because transmission providers can avoid 

granting credits if they fail to jointly plan with their transmission customers. 

44. Finally, there is also concern about the appropriate rate for transmission capacity 

that has been resold by the original transmission customer. Under Order No. 888, such 

capacity may be priced at the higher of the original rate, the transmission provider’s 

maximum stated firm rate, or the assignor’s opportunity costs capped at the cost of 

expansion. Customers complain that this policy does not work when opportunity costs 

exceed the embedded cost rate, because the assignor must make a FPA section 205 filing 
Docket Nos. RM05-25-000 and RM05-17-000 - 37 – 

with the Commission that estimates its opportunity cost over the term of the reassignment 

as well as the cost of system expansion. The time and effort required to complete the 

regulatory process appears to inhibit such reassignments. 

45. Although Order No. 888 was primarily directed at establishing the non-rate terms 

and conditions of open access, the rule did adopt certain pricing policies that were 

associated with the form of open access being ordered. After reviewing the comments, 

we believe certain reforms are appropriate because some of the pricing policies 

associated with the pro forma OATT are no longer just and reasonable or are otherwise 

unduly discriminatory. However, we do not intend to pursue generic reform of other 

pricing policies that are better addressed on a region- or case-specific basis, such as the 

pricing of new transmission facilities. 

F. EPAct 2005 Emphasized Certain Policies and Priorities for the 

Commission 

46. The reforms we propose today also are consistent with the policies and priorities 

embodied in EPAct 2005, in which Congress emphasized many of the principles reflected 

in this NOPR. 

47. First, Congress in EPAct 2005 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 38 – 

and reducing the cost of delivered power by reducing transmission congestion.”62 

FPA section 219 requires the Commission to “promot[e] 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.”63 Congress also gave the Commission certain “backstop” transmission siting 

authority, and authorized the creation of interstate compacts establishing transmission 

siting agencies.64 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 load-serving entities, and enables load-serving entities to secure firm 

transmission rights . . . on a long-term basis for long-term power supply arrangements 

made, or planned, to meet such needs.”65 Although these provisions are, or will be, 

addressed primarily in other proceedings, our NOPR is consistent with these provisions 

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

824s). The Commission issued a NOPR implementing such an incentive rate program in 

November 2005. See Promoting Transmission Investment through Pricing Reform, 70 FR 

71409 (Nov. 29, 2005), FERC Stats. & Regs. ¶ 32,593 (2005). 

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

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

824p). 

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

16 U.S.C. 824q). 
Docket Nos. RM05-25-000 and RM05-17-000 - 39 – 

because it supports new infrastructure by reforming the transmission planning process to 

ensure that it is open, transparent and nondiscriminatory.66 

48. 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.”67 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.” Our NOPR 

similarly seeks to promote greater transparency in the provision of transmission service in 

many important areas, including ATC calculation and transmission planning. 

49. Finally, Congress emphasized compliance with the Commission’s regulations, 

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

 66 We note that we also have proposed to implement FPA section 217(b)(4) in a 

separate rulemaking in Docket No. RM06-8-000. 

67 EPAct 2005 sec. 1281 (to be codified at 16 U.S.C. 824t). 
Docket Nos. RM05-25-000 and RM05-17-000 - 40 – 

statutes and regulations.68 This new authority buttresses the Commission’s efforts to 

enforce public utility OATTs and the regulations requiring transmission information to be 

posted on OASIS. As we explained in the Enforcement Policy Statement, 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.69 The NOPR is 

fully consistent with these principles because it seeks, in many areas, to clarify our rules 

to facilitate compliance by transmission providers. 

IV. Summary, Scope and Applicability of the Proposed Rule 

50. This section provides: (1) a summary of the major components of the NOPR, 

(2) a description of the core elements of Order No. 888 that we propose to retain, and 

(3) a discussion of the applicability of the proposed rule to various entities. 

A. Summary of Proposed Reforms

51. Consistency and transparency of ATC calculations. The Commission finds 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 

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

16 U.S.C. 825o-1 (2000). 

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

Enforcement, 113 FERC ¶ 61,068 (2005) (Enforcement Policy Statement). 
Docket Nos. RM05-25-000 and RM05-17-000 - 41 – 

the discretion, and hence the ability and opportunity, to favor itself and its affiliates over 

third parties in how it calculates and allocates ATC and, therefore, may be unjust, 

unreasonable, unduly discriminatory and preferential. As a result, we propose to give the 

industry specific guidance and a firm deadline to develop certain requirements to make 

the process of calculating ATC and the process of exchanging data between transmission 

providers about ATC more consistent. In addition, we propose to amend pro forma

OATT requirements as well as our OASIS regulations to increase the transparency in 

how ATC is calculated. 

52. Requirement for coordinated, open and transparent transmission planning. The 

Commission finds that Order No. 888 does not contain sufficient protections to guard 

against undue discrimination in transmission system planning. This, in turn, can affect a 

customer’s ability to obtain transmission service and the price it pays for transmission. 

Specifically, Order No. 888 does not require sufficient coordination, openness, and 

transparency in transmission planning to ensure that new infrastructure is constructed to 

meet the needs of all eligible customers on a not unduly discriminatory basis. 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 propose to 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 propose eight 
Docket Nos. RM05-25-000 and RM05-17-000 - 42 – 

planning principles 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. 

53. 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 intend to initiate 

broad reform of transmission pricing policy through this NOPR. However, we have 

identified several pricing rules that are part and parcel of OATT service that merit 

reform. 

• Energy and Generator Imbalance Charges. We find that existing energy and 

generator imbalance charges may be excessive and otherwise unrelated to the cost 

of providing the service and, therefore, propose to reform energy and generator 

imbalance pricing. We propose to require that all such imbalance charges 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 may no longer be just and reasonable and, therefore, 
Docket Nos. RM05-25-000 and RM05-17-000 - 43 – 

propose to eliminate the cap. We believe that removing the cap will eliminate an 

unnecessary impediment to the resale of capacity, which in turn should increase 

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

reasonable and not unduly discriminatory. We seek comment on this proposal 

and, in particular, the nature of the reporting obligations that should be imposed as 

part of lifting the cap on reassignment. 

• Crediting of Customer-Owned Facilities. We propose to 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 

propose to eliminate the requirement that new facilities can receive credits only if 

they are "jointly planned" because this requirement may provide a disincentive to 

coordinated planning. Rather, we propose that such new facilities be eligible for 

credits if: (1) such facilities are integrated into the operations of the transmission 

provider’s facilities, and (2) such facilities would be eligible for inclusion in the 

transmission provider’s annual transmission revenue requirement if owned by the 

transmission provider. 

54. Improvements to Point-to-Point Service. The Commission concludes that the 

existing methods for evaluating requests for long-term firm point-to-point service may no 

longer be just, reasonable and not unduly discriminatory. 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 44 – 

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 time-consuming and 

costly facilities studies does the transmission provider evaluate redispatch options, 

including whether they are less expensive than the upgrade options. The Commission 

proposes to address this problem by clarifying that a transmission provider must use all of 

its available redispatch options to satisfy a request for firm point-to-point service and, at 

the transmission customer's option, these redispatch options must be studied before the 

customer is obligated to incur the costs and time delays associated with a facilities study. 

The Commission also seeks comment on whether this remedy is adequate or, 

alternatively, whether the Commission should modify the nature of point-to-point service 

to require that transmission providers offer a "conditional firm" service that would be 

subject to curtailment prior to firm service only a limited number of hours of the year. 

55. 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 

“rollover” their contracts, is in need of reform. The Commission proposes to revise that 

provision to apply to contracts that have a minimum term of five years, rather than the 

current minimum term of one year. We conclude that this reform will ensure that the 

rollover right is enjoyed by transmission customers that have made a significant 

commitment to (and investment in) the transmission grid. In addition, the Commission 
Docket Nos. RM05-25-000 and RM05-17-000 - 45 – 

proposes that a transmission customer eligible for rollover rights must provide notice of 

whether or not it will exercise its right of first refusal to renew the contract no less than 

one year prior to the expiration date of the transmission service agreement, rather than 

within the current 60-day period. 

56. Increases in transparency to lessen the opportunities to discriminate and reduce 

transaction costs. In addition to the increased transparency we propose to require 

regarding the calculation of ATC and transmission planning, we propose to increase the 

transparency of transmission service provided under the pro forma OATT in several other 

respects. For example, we propose to require transmission providers and their network 

customers to use the transmission provider’s OASIS to request designation of a new 

network resource and to terminate the designation of an existing network resource. In 

addition, we propose to require the transmission provider to modify its OASIS so that 

requests to designate and terminate a network resource can be queried. We also propose 

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. 

Finally, we propose to 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. 

57. Strengthening enforcement of the pro forma OATT. Our proposed reforms 

include several clarifications of the terms and conditions of the pro forma OATT that 

have made undue discrimination difficult to detect and otherwise frustrated enforcement 
Docket Nos. RM05-25-000 and RM05-17-000 - 46 – 

of the obligation to provide open access, non-discriminatory transmission service. 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. In addition, we propose 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 

propose to require transmission providers to post specific performance metrics related to 

their completion of studies required under the pro forma OATT. We note that the 

Commission will continue to audit compliance with the pro forma OATT, and toward 

that end propose to require transmission information kept on OASIS to be retained for 

audit purposes for five years. Finally, we make a number of proposals relating 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. 

58. Miscellaneous OATT improvements. We propose 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: 

Hourly Firm. We propose to require transmission providers to offer hourly firm 

service under the pro forma OATT. 

Designation of network resources. We propose to make a number of clarifications 

related to the types of agreements that may be designated as network resources, the 
Docket Nos. RM05-25-000 and RM05-17-000 - 47 – 

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 propose to require customers to submit an attestation with each 

application to designate a new network resource. 

Reservation priorities. We propose to change the priority rules to give priority to 

pre-confirmed transmission service requests submitted in the same time period. We also 

propose to add price as a tie-breaker in determining reservation queue priority when the 

transmission provider is willing to discount transmission service. 

Clarifications related to network service. We propose to clarify that a network 

customer may not use secondary network service to bring energy onto its system to 

support an off-system sale if the purchased power does not displace the customer’s own 

higher cost generation. We also propose clarifications related to use of network service 

on an “as available basis” and to “redirects” of network service. 

Definitions. In addition to some minor revisions, we propose to add a definition of 

“non-firm sales” to the pro forma OATT and propose to amend the definition of Good 

Utility Practice to reference the definition of “reliable operation” adopted in EPAct 2005. 

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

59. Although we are proposing many important reforms to Order No. 888 and the pro 

forma OATT, we also wish to emphasize that we propose to retain many of the core 

elements of Order No. 888. We note that many of these core elements enjoy broad 

support across many sectors of the industry. In their comments, APPA, EEI, and 
Docket Nos. RM05-25-000 and RM05-17-000 - 48 – 

NARUC urge the Commission to proceed carefully in reforming Order No. 888, focusing 

on incremental reforms not 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, where appropriate, respond to the comments on 

these points that were received in the NOI. 

1. Federal/State Jurisdiction 

60. 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.70 

Though the Commission adopted a test for determining which facilities were used for 

retail transmission, as opposed to local distribution to end-users,71 the Commission stated 

that it generally would defer to determinations by state regulatory authorities concerning 

where to draw the jurisdictional line under that test.72 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.”73 The U.S. Supreme Court affirmed the Commission’s 

 70 Order No. 888 at 31,781. 

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

72 Id. at 31,781. 

73 Id.
Docket Nos. RM05-25-000 and RM05-17-000 - 49 – 

decision to assert jurisdiction over unbundled but not bundled retail transmission, finding 

that the Commission made a statutorily permissible choice.74 

61. We propose to retain the jurisdictional divide we established in Order No. 888. 

We also are mindful of the need for heightened cooperation between federal and state 

regulators in areas where there are overlapping federal and state policy concerns. 

Moreover, our jurisdictional determination was sustained by the U.S. Supreme Court and 

has been accepted by industry and state regulatory authorities. We see no reason to 

disturb that determination now. 

2. Native Load Protection 

62. Order No. 888 did not require transmission providers to unbundle transmission 

service to their retail native load nor did it require that bundled retail service be taken 

under the terms of the pro forma OATT.75 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.76 As noted above, Order No. 888 granted a rollover right to existing firm service 

customers,77 but allowed transmission providers to restrict that rollover right if the 

 74 See New York v. FERC, 535 U.S. 1, 28 (2002). 

75 Order No. 888 at 31,745. 

76 Id. at 31,694. 

77 Id.; pro forma OATT section 2.2. 
Docket Nos. RM05-25-000 and RM05-17-000 - 50 – 

capacity was reasonably forecasted to be needed to serve native load customers, as long 

as that restriction was specified in the customer’s service contract.78

63. 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. It allows load-serving entities to use their own and contracted-for 

transmission capacity to the extent required to meet their service obligations, without 

being subject to charges of unlawful discrimination. Among other things, FPA 

section 217 states that it does not require the abrogation of any contract or service 

agreement for firm transmission service or rights in effect as of the date of enactment.79 

64. In the NOI, the Commission stated that it was not proposing to change the 

protection of native load embodied in Order No. 888.80 The Commission sought 

comment on whether the approach the Commission took in Order No. 888 is the same as 

that set forth in FPA section 217. 

Comments

65. Several commenters argue that the approach the Commission took in Order 

No. 888 is largely consistent with the treatment of native load preference in FPA 

 78 Order No. 888-A at 30,198. 

79 16 U.S.C. 217(f). 

80 NOI at P 9. 
Docket Nos. RM05-25-000 and RM05-17-000 - 51 – 

section 217.81 They state that Order No. 888 makes clear that native load has a priority 

right to a transmission providers’ capacity and that transmission providers may reserve a 

portion of their capacity for native load growth. 

66. Other commenters perceive varying degrees of difference between Order No. 888 

and FPA section 217.82 EEI states that FPA section 217 extends native load protection to 

all load-serving entities that have direct or indirect service obligations to end-users for 

terms of one year or more, while Order No. 888 does not. Nevada Companies and TAPS 

argue that the FPA section 217 requirement that the Commission exercise its authority to 

facilitate the planning and expansion of transmission facilities to satisfy the service 

obligations of load-serving entities necessitates changes to Order No. 888. 

67. Several commenters argue that FPA section 217 requires the Commission to 

revisit its rollover rights policy.83 Duke maintains that the current Commission approach 

is not the same as set forth in either Order No. 888 or FPA section 217 because the 

Commission’s current approach to rollover rights does not meaningfully recognize the 

native load preference. Commission decisions since Order No. 888, according to Duke, 

have weakened the native load preference envisioned in Order No. 888 to the point where 

 81 E.g., Memphis Light, Newmont Mining Reply Comments, Progress Energy, and 

TDU Systems. 

82 E.g., Duke, EEI, Metropolitan Water District, and Southern. 

83 E.g., Duke, Entergy, LPPC, Progress Energy, Salt River, Santee Cooper, and 

Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 52 – 

the Commission’s treatment of the native load preference is not what Congress provides 

in FPA section 217. LPPC argues that FPA section 217 reverses Commission precedent 

that makes it impossible to recall capacity for native load once it is subject to a rollover 

right. 

68. EEI states that in order to harmonize Order No. 888 rollover rights with the native 

load protections contained in FPA section 217, the Commission should revise the pro 

forma OATT to require a notice period for rollover rights that is consistent with the time 

needed to plan for and construct transmission facilities to serve native load customers and 

the rollover customer. EEI and Salt River argue that FPA section 217 requires that the 

Commission permit load-serving entities to implement curtailment procedures that 

recognize native load service priorities. 

69. Metropolitan Water District argues that the mandate to preserve native load 

preference is complicated further when a transmission owner has transferred operational 

control to an ISO or RTO. In such a scenario, to honor the native load preference in FPA 

section 217, Metropolitan Water District contends that the Commission either should 

reconsider its prior rulings rejecting the allocation of physical rights to serve native load 

or should require ISOs and RTOs to issue financial rights options, in addition to financial 

right obligations, so that load-serving entities have a greater ability to avoid congestion 

costs in serving their native load. 
Docket Nos. RM05-25-000 and RM05-17-000 - 53 – 

Discussion 

70. The Commission concludes that the protection of native load embodied in Order 

No. 888 is consistent with FPA section 217, and we reaffirm our commitment to the 

protection of native load. Order No. 888 gave public utilities the right to reserve existing 

transmission capacity needed for native load growth reasonably forecasted within the 

utility's current planning horizon. It also allowed transmission providers to restrict 

rollover rights based on a reasonably forecasted need at the time the contract is executed. 

This approach 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. Though commenters appear to believe FPA 

section 217 would support the cancellation of contracts that include rollover rights, FPA 

section 217 by its terms does not contemplate abrogation of existing transmission service 

contracts.84 However, to the extent commenters argue that the terms of service and 

notice periods associated with the OATT rollover rights are too short to protect native 

load adequately, we note that we are proposing to extend them in this NOPR. 

71. In response to Metropolitan Water District, the Commission finds that the issue of 

firm transmission rights in organized markets is best addressed as part of the long-term 

firm transmission rights rulemaking in Docket Nos. RM06-8-000 and AD05-7-000. 

 84 See FPA section 217(f) (explaining that section 217 does not abrogate any firm 

service agreements or rights in effect as of the date of enactment). 
Docket Nos. RM05-25-000 and RM05-17-000 - 54 – 

We further note, in response to the comments of Nevada Companies and TAPS, that we 

are proposing a coordinated and regional planning process to facilitate the planning and 

expansion of transmission facilities pursuant to FPA section 217. 

3. The Types of Transmission Services Offered 

72. 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 NOI, the Commission sought comments on whether the 

Commission should require transmission providers to offer transmission services in 

addition to, or in place of, the point-to-point and network services prescribed in the 

OATT. 

73. Among other questions, the Commission asked whether network service alone or 

both network and point-to-point services should be converted into a single contract 

demand service.85 Generally speaking, contract demand service is a hybrid of point-topoint and network services that is reservation-based and allows transmission customers to 

receive a firm entitlement to integrate multiple resources and deliver energy to multiple 

points, without paying a separate charge for each point of receipt or delivery. Contract 

demand service would allow current point-to-point customers to avoid having to arrange 

and pay for separate reservations for each point of receipt. And current network 

 85 For examples of contract demand service, the Commission cited Florida Power 

Corp., 71 FERC ¶ 61,248 (1995); Wisconsin Electric Power Co., 72 FERC ¶ 61,033 

(1995); and Florida Power Corp., 81 FERC ¶ 61,247 (1997). 
Docket Nos. RM05-25-000 and RM05-17-000 - 55 – 

customers would be allowed to pay for transmission based on the amount of their 

reservation rather than customer loads at a delivery point. 

Comments

74. Most commenters argue against requiring that network service alone or in 

combination with point-to-point service be converted into contract demand service.86 

Some warn that the imposition of this service would interfere with efficient transmission 

system planning and operation due to increased capacity reservations that would go 

unused.87 They also argue that it would result in significant cost shifts among 

transmission customers if not priced correctly. FP&L argues that the current services are 

a better match for the actual use of the transmission system and thereby permit more 

ATC to be available. 

75. Some commenters ask that the Commission require transmission providers to offer 

contract demand service as an additional transmission service option in the pro forma

OATT.88 AMP-Ohio argues that, as long as Commission policy requires network 

customers to pay load-ratio network transmission charges for load served with behind-

 86 E.g., Ameren, APPA, Bonneville, Calpine, EEI, EPSA, Fallon Reply 

Comments, FP&L, NRECA, PacifiCorp, Southern, Suez Energy NA, TVA, TAPS, and 

TDU Systems. 

87 E.g., EEI, FP&L, KCP&L, and TVA. 

88 E.g., AMP-Ohio, APPA, Cogeneration Association of California Reply 

Comments, Constellation, EPSA, FMPA Reply Comments, Midwest Municipals, 

PacifiCorp, and Public Power Council. 
Docket Nos. RM05-25-000 and RM05-17-000 - 56 – 

the-meter generation, contract demand network service is essential to avoid unduly 

discriminatory transmission charges. Midwest Municipals and FMPA argue that the 

Commission should order contract demand service where the transmission provider does 

not plan and operate its system to meet total customer load because, as the Commission 

stated in Order No. 888, full network service is essential for achieving comparability and 

efficient integration of power supply and load. FMPA contends that where a customer 

needs network service from another system for only part of its load, it would benefit from 

being able to buy system power from multiple designated resources for part of its load. 

In this way, FMPA continues, the transmission provider would not have the planning 

obligation for the customer’s entire load, perhaps avoiding or delaying expensive 

transmission additions. FMPA claims that such service would tend to benefit all 

transmission users because it would allow a more efficient use of the grid and provide 

additional transmission revenues. 

76. Other commenters state that transmission providers should have the option 

whether to offer contract demand or other customized transmission services.89 LPPC 

argues that the Commission should allow a transmission provider to voluntarily provide 

alternative forms of transmission service where circumstances support their 

implementation, with the caveat that such service must not place any market participant 

at a disadvantage or increase transmission rates for network or point-to-point customers. 

 89 E.g., LPPC, NRECA, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 57 – 

Southern proposes that the pro forma OATT be modified to include a process through 

which a transmission provider may propose to adopt new services that customers 

specifically request. 

77. Commenters also raise general concerns regarding the use and potential abuse of 

network contract demand service. For example, MidAmerican argues that contract 

demand service should not be used as a means for transmission customers with behindthe-meter generation to avoid paying for a load-ratio share of a system that was built to 

support their entire load and on which they rely for service. Rather, MidAmerican 

continues, network contract demand service should be limited to situations in which 

deliverability is physically limited, such as where the integrated transmission system does 

not have the capacity to serve all the load at a designated point of delivery. EEI argues 

that the Commission should not convert network service to network contract demand 

service because conversion would result in a substantial reduction in ATC as it would 

provide contract rights on the transmission system on an around-the-clock basis that are 

equal to network load’s monthly or annual peak loads. 

Discussion

78. We propose to retain the services we ordered in Order No. 888: firm and non-firm 

point-to-point service and firm network service. We do not propose requiring 

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. The Commission continues to believe that network and point-to-point 
Docket Nos. RM05-25-000 and RM05-17-000 - 58 – 

services are the appropriate base-line service offerings in the OATT. Although forms of 

contract demand service have been approved by the Commission, and the service may 

provide benefits to certain customers, sufficient potential drawbacks exist that prevent us 

from concluding that it is a necessary transmission service that should be included in the 

pro forma OATT. 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. While the Commission concludes that 

it will not require all transmission providers to offer this service, we acknowledge that the 

introduction of this service on a voluntary basis may be appropriate in certain 

circumstances. 

79. Although we are not proposing to require that transmission providers adopt 

contract demand service, we note that the commenters who support this service appear 

concerned principally with inequities in the pricing of network integration service. The 

Commission is addressing certain of these concerns elsewhere in the NOPR. For 

example, in this NOPR, we propose to modify our treatment of transmission credits for 

new transmission facilities and clarify that the transmission provider must satisfy the 

comparability requirement when including transmission facilities in its rate base for pro 

forma OATT purposes. We also address concerns regarding the linkage between how the 

transmission provider plans and operates its system through proposed revisions to 

planning and ATC. 
Docket Nos. RM05-25-000 and RM05-17-000 - 59 – 

4. Functional Unbundling

80. When the Commission proposed the open access policy that culminated in Order 

No. 888, there was considerable debate about whether corporate unbundling (in which a 

public utility’s transmission and generation assets would be placed in separate corporate 

entities) was necessary to ensure non-discriminatory open access transmission service. 

The Commission decided to mandate functional, rather than corporate, unbundling of 

transmission and generation services. In Order No. 888, the Commission explained that 

functional unbundling has three components: 

1. A public utility must take transmission services (including ancillary 

services) for all of its new wholesale sales and purchases of energy under 

the same tariff of general applicability as do others; 

2. A public utility must state separate rates for wholesale generation, 

transmission, and ancillary services; 

3. A public utility must rely on the same electronic information network that 

its transmission customers rely on to obtain information about its 

transmission system when buying or selling power.90 

81. 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 

 90 Order No. 888 at 31,654. 
Docket Nos. RM05-25-000 and RM05-17-000 - 60 – 

transmission assets. There remain, however, a significant number of vertically-integrated 

public utilities that have operated under the functional unbundling approach. 

Comments 

82. Retention of Order No. 888’s functional unbundling approach is supported by a 

number of commenters. For example, the LPPC states that vertical integration remains a 

viable business model for serving customers reliably and at economic rates. LG&E 

posits that, absent a proven and real level of abuse, major structural changes are 

unwarranted. NARUC argues that the issue of whether there should be structural 

separation of generation from transmission is best left to the states. NPPD alleges that 

mandatory vertical unbundling would do more harm than good by threatening the 

continued economic operation of those utilities that continue to provide bundled service 

to their retail native load customers. The North Carolina Commission does not believe 

the evidence in that state supports the imposition of structural remedies. 

83. Some commenters, however, continue to urge the Commission to impose 

structural separation. National Grid contends that the best way to eliminate the 

possibility of undue discrimination is to separate the ownership and operation of the 

transmission system from interests in the market. Calpine urges the Commission to 

structurally separate the merchant function that is engaged in selling power for resale 

from those who control access to transfer capability and service, not just those who 

operate the transmission system. TAPS argues that structural solutions are preferable to 

behavioral rules. 
Docket Nos. RM05-25-000 and RM05-17-000 - 61 – 

84. Many commenters favoring structural separation urge the Commission to impose 

an independent transmission coordinator requirement. These commenters would have 

transmission providers employ an independent entity to administer their OATTs, 

performing such functions as maintaining the utility’s OASIS, granting or denying 

service requests, reviewing system impact and facilities study results, and overseeing 

decisions with respect to line ratings, transmission outages and generation dispatch.91 

Other commenters oppose the imposition of a potentially costly new layer of 

bureaucracy, at least on a generic basis.92

Discussion

85. We propose to preserve the functional unbundling approach adopted by Order 

No. 888. For public utilities that kept transmission and generation assets in the same 

corporate entity, the Commission imposed strict Standards of Conduct that required 

separation of the utilities’ transmission system operations and wholesale marketing 

functions.93 These Standards of Conduct were replaced by a broader set of rules adopted 

 91 E.g., Arkansas Commission, Calpine, Constellation, EPSA, and PPL. 

92 E.g., APPA, NRECA, and TAPS. 

93 Order No. 889 at 31,595. 
Docket Nos. RM05-25-000 and RM05-17-000 - 62 – 

in Order No. 2004.94 These rules require that employees engaged in transmission 

functions operate separately from employees of energy affiliates and marketing affiliates. 

A number of information sharing restrictions also apply, which prohibit transmission 

providers from allowing employees of their energy and marketing affiliates to obtain 

access to transmission or customer information, except via OASIS. 

86. The Commission aggressively enforces the Standards of Conduct. 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 function and information restrictions in Order 

No. 2004 are implemented. 

87. The Commission has resolved a number of complaints related to the Standards of 

Conduct and the accompanying OASIS posting requirements.95 In Order No. 888, the 

Commission noted that the possibility of filing a complaint under FPA section 206 is an 

 94 See Standards of Conduct for Transmission Providers, Order No. 2004, 68 FR 

69134 (Dec. 11, 2003), FERC Stats. & Regs. ¶ 31,155 (2003), order on reh'g, Order 

No. 2004-A, 69 FR 23562 (Apr. 29, 2004), FERC Stats. & Regs. ¶ 31,161 (2004), order 

on reh'g, Order No. 2004-B, 69 FR 48371 (Aug. 10, 2004), FERC Stats. & Regs. 

¶ 31,166 (2004), order on reh'g, Order No. 2004-C, 70 FR 284 (Jan. 4, 2005), FERC 

Stats. & Regs. ¶ 31,172 (2005), order on reh'g, Order No. 2004-D, 110 FERC ¶ 61,320 

(2005), appeal docketed sub nom. National Gas Fuel Supply Corporation v. FERC, 

No. 04-1183 (D.C. Cir. June 9, 2004), codified at 18 CFR Part 358 (2005). 

95 See Aquila Energy Marketing Corp. v. Niagara Mohawk Power Corp., 87 FERC 

¶ 61,328 (1999) (finding that off-OASIS communication between utility and its 

marketing affiliate led to preferential treatment of the affiliate). 
Docket Nos. RM05-25-000 and RM05-17-000 - 63 – 

additional safeguard if a public utility seeks to circumvent the functional unbundling 

requirement. The Commission’s Enforcement Hotline likewise is available to customers 

that do not wish to file a formal complaint. 

88. In addition, one of the criticisms of the functional unbundling requirement is that 

Order No. 888 leaves vertically integrated utilities with too much discretion in applying 

the OATT and gives them an incentive to use this discretion to their advantage. We 

agree that the existing pro forma OATT provides too much discretion in certain important 

areas. It is for this reason - as explained elsewhere in the NOPR - that we are proposing 

to require greater clarity and transparency in several areas of OATT administration. We 

believe these reforms will limit the discretion of transmission providers and make any 

remaining attempts to discriminate much easier to detect. 

89. We believe that this increased clarity and transparency, when coupled with the 

Standards of Conduct and a rigorous enforcement program, will ensure that the functional 

unbundling requirement will serve its original purpose. As a result, just as the 

Commission concluded in Order No. 888 that more intrusive and costly corporate 

unbundling was not necessary, the Commission again concludes that there is no need to 

impose a corporate or structural unbundling requirement at this time. We believe that the 

pro forma OATT, if properly clarified and enforced, will enable us to eliminate the 

opportunity for undue discrimination in the provision of transmission service. 

90. For the same reasons, we also decline to mandate an independent transmission 

coordinator for all transmission providers. We have concluded that such entities may be 
Docket Nos. RM05-25-000 and RM05-17-000 - 64 – 

appropriate in certain circumstances and we support voluntary efforts to rely on them.96 

We do not agree, however, that there is sufficient basis for requiring them as a generic 

remedy for undue discrimination. 

91. Our proposal to retain the functional unbundling approach of Order No. 888 does 

not suggest, however, a lack of support for structural changes that may be undertaken on 

a voluntary basis by each region, such as transmission-only companies, RTOs, or other 

reforms. We continue to support such efforts as potentially providing significant benefits 

in several areas, including, but not limited to, increased infrastructure investment and 

addressing regional issues such as cost recovery, pancaked rates, loop flow, and 

congestion management. At this time, we believe such efforts are best developed on a 

voluntary basis. 

C. Applicability of the Proposed Rule

1. Public Utility Transmission Providers

92. Pursuant to its authority under FPA sections 205 and 206, the Commission in 

Order No. 888 required all public utilities that owned, controlled, or operated facilities 

used for transmitting electric energy in interstate commerce to file open access 

transmission tariffs that contained minimum terms and conditions of non-discriminatory 

 96 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). 
Docket Nos. RM05-25-000 and RM05-17-000 - 65 – 

service. The Commission recognized, however, that there may be circumstances in 

which a public utility believes that the pro forma OATT does not provide sufficient 

flexibility.97 In addition, the Commission acknowledged that a public utility might be 

willing to offer superior non-rate terms and conditions. As a result, the Commission 

allowed a transmission provider to justify variations from the non-price terms and 

conditions of the pro forma OATT under two circumstances. First, certain provisions of 

Order No. 888 specifically allowed public utilities to use alternatives that were justified 

by “regional differences.” When submitting those provisions, public utilities were 

permitted to follow regional practices when doing so was "reasonable, generally accepted 

in the region, and consistently adhered to by the transmission provider,"98 as long as the 

utilities identified the regional practices in their compliance filings. Second, in 

subsequent FPA section 205 proceedings, public utilities were permitted to propose 

changes to any pro forma OATT provision that were "consistent with or superior to" the 

terms of the pro forma OATT. 

93. In the NOI, the Commission expressed the preliminary view that reforms to the 

pro forma OATT and public utilities’ OATTs appear necessary and sought comment on 

how best to accomplish that. In particular, the Commission sought comment on whether 

 97 Order No. 888 at 31,770. 

98 Id.
Docket Nos. RM05-25-000 and RM05-17-000 - 66 – 
Docket Nos. RM05-25-000 and RM05-17-000 - 67 – 

reforms to Order No. 888 should be applied to all public utility transmission providers, 

including those that are approved ISOs, RTOs, or independent transmission coordinators. 

Comments

94. Independent system operators such as MISO, CAISO, and ISO New England 

submit that many of the concerns raised by the Commission in the NOI already have 

successfully been addressed by the operation of ISOs and RTOs. Similarly, EEI argues 

that many of the issues addressed in the NOI are not applicable to RTOs and ISOs 

because RTOs and ISOs are independent of all market participants and therefore are 

presumed to not engage in undue discrimination or preferential treatment. PJM argues 

that, because of its independence, the transparency of its procedures, and the progress 

achieved in developing effective financial and non-financial congestion management 

tools, PJM structurally addresses the continuing concerns of the Commission regarding 

persistent undue discrimination and preference in the industry. 

95. EPSA states that it may not be necessary to apply all aspects of the new OATT to 

ISOs or RTOs. However, rather than delineating either each term that would not apply to 

an RTO or how such terms might be modified in an RTO tariff, EPSA recommends that 

the Commission require RTOs, ISOs, and independent transmission coordinators to 

submit compliance filings upon issuance of the new pro forma OATT but allow them to 

propose waivers of the new requirements based upon appropriate justification. 

96. EEI argues that, to the extent that the Commission requires RTOs and ISOs to 

amend their open access transmission tariffs, the Commission should establish flexible 
Docket Nos. RM05-25-000 and RM05-17-000 - 68 – 

procedures that provide the RTOs and ISOs the right to customize their OATTs 

consistent with their independent status. 

97. Other commenters argue that reforms to existing OATTs should be applied to all 

market entities, including ISOs, RTOs and independent transmission coordinators.99 

LPPC states that there is little reason for the Commission to be more deferential in 

considering deviations from the pro forma OATT proposed by RTOs or ISOs than it is 

with respect to investor-owned utilities. 

Discussion

98. The Commission proposes to apply the final rule to all public utility transmission 

providers. The Commission proposes to require all such transmission providers to submit 

FPA section 206 compliance filings, within 60 days following publication of the final 

rule in the Federal Register, that contain the non-rate terms and conditions set forth in the 

final rule. We note 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. We seek comment on an appropriate time period in which to 

require the submission of these attachments. 

99. As we did in Order No. 888, after making their FPA section 206 compliance 

filings, we propose to allow transmission providers to submit filings under FPA 

 99 E.g., Calpine, LPPC, NRECA, and Santa Clara. 
Docket Nos. RM05-25-000 and RM05-17-000 - 69 – 

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. 

100. With respect to an RTO or ISO, we recognize that such an entity may already have 

tariff terms and conditions that are superior to the pro forma OATT. Thus, we propose to 

require RTO and ISO transmission providers to submit FPA section 206 compliance 

filings, within 90 days following 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. Similarly, after making their FPA section 206 

compliance filings, we propose to allow RTOs and ISOs 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. 

101. We generally note that the purpose of this NOPR is not to redesign approved, 

fully-functional RTO or ISO markets. We do not expect that substantial changes to those 

markets would be required as a result of this NOPR. For example, some RTOs or ISOs 

have eliminated point-to-point service for internal transactions in favor of a form of more 

flexible network service. Thus, we would not expect our reforms to ATC to require 

changes to the way in which such RTOs or ISOs assess whether capacity for traditional 

network or point-to-point service is available within their footprints. However, there may 
Docket Nos. RM05-25-000 and RM05-17-000 - 70 – 

be elements of the proposed reforms that are superior to what currently exists in some 

RTOs or ISOs, e.g., transparency, data exchange or planning, which would require the 

RTO or ISO to conform to the pro forma OATT. 

2. Non-Public Utility Transmission Providers/Reciprocity 

102. 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.100 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 

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. 

103. 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 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 

 100 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. RM05-25-000 and RM05-17-000 - 71 – 

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.101

104. In EPAct 2005, Congress authorized, but did not require, the Commission to order 

non-public utilities (or “unregulated transmitting utilities”) to provide transmission 

services. Section 1231 of EPAct 2005 establishes a new section 211A in Part II of the 

FPA, which 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 it can reasonably be read to permit the Commission to order the non- 

 101 See Order No. 888-A at 30,285-86. 
Docket Nos. RM05-25-000 and RM05-17-000 - 72 – 

public utility to provide “open access” transmission service, i.e., service to all eligible 

customers. 

105. In the NOI, we sought comment on whether the Commission should exercise the 

authority granted to it by Congress in FPA section 211A. If so, we asked whether the 

Commission should impose this requirement on all unregulated transmitting utilities 

through a rulemaking proceeding, or whether the Commission should instead apply this 

new law on a case-by-case basis, through complaints, motions seeking enforcement, or 

sua sponte action by the Commission. 

Comments

106. Several non-public utility commenters suggest that the Commission should not use 

the authority granted by FPA section 211A in a generic fashion.102 They argue that there 

is no need to require unregulated transmitting utilities either to file open access tariffs 

with the Commission or to require that they adhere to a pro forma OATT. APPA asserts 

that while the Commission may act under FPA section 211A to remedy particular issues 

that are brought to its attention with respect to lack of access, there is simply no basis for 

concluding that there currently exists a general problem regarding the provision of 

transmission service by non-public utility transmission providers which calls for a 

 102 E.g., Chelan, Douglas, LDWP, LPPC, Northwest Unregulated TUs, Public 

Power Council, Rural Utilities Service, Sacramento, Santee Cooper, Snohomish, Tacoma, 

TAPS, and TVA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 73 – 

generic solution. LPPC proposes a regime of voluntary compliance with a set of 

proposed comparability guidelines. 

107. Many commenters argue that the Commission should exercise its authority granted 

by FPA section 211A by establishing a rule to require unregulated transmitting utilities to 

provide service under the pro forma OATT.103 EEI believes a rulemaking is essential to 

ensure that all utilities required to provide open access under FPA section 211A do so 

and that the Commission should, at a minimum, require unregulated transmitting utilities 

to file and provide service under the pro forma OATT. EPSA and Sempra Global suggest 

an approach that would not require an unregulated transmitting utility to file an OATT 

with the Commission until it receives a request for service. 

108. EEI argues that the Commission should use FPA section 211A to require 

unregulated transmitting utilities to provide all services they are capable of providing, not 

just those that they provide to themselves. In contrast, APPA states that FPA 

section 211A establishes a “comparability” standard applicable to non-public utility 

transmission owner rates, and a “comparable and not unduly discriminatory or 

preferential” standard for terms and conditions. APPA further states that FPA 

section 211A requires that unregulated transmitting utilities provide transmission service 

to others at rates, terms and conditions “comparable to those under which the unregulated 

 103 E.g., Ameren, California Commission, Calpine, Cinergy, EEI, First Energy, 

Memphis Light, Nevada Companies, Northwest IPPs, PNM-TNMP, PPL, Progress 

Energy, and Suez Energy NA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 74 – 

transmitting utility provides transmission services to itself,” rather than transmission 

services that they are “reasonably capable of providing.” 

109. The Canadian Electricity Association believes that the adoption of FPA 

section 211A requires the Commission to revisit the reciprocity requirement of Order 

No. 888. According to the Canadian Electricity Association, EPAct 2005 lowered the bar 

for domestic unregulated transmitting utilities, requiring them only to provide service 

under terms and conditions that are comparable to those they apply to themselves, rather 

than terms and conditions that substantially conform or are superior to those in the pro 

forma OATT. If the Commission does not make corresponding changes to the manner in 

which the reciprocity requirement currently applies to Canadian entities, it argues, the 

result will be domestic unregulated transmitting utilities being treated better than 

Canadian entities, which would violate the national treatment obligations under the North 

American Free Trade Agreement. The Canadian Electricity Association argues that the 

reciprocity requirement under Order No. 888 must be modified to require that a Canadian 

entity that seeks open access in the U.S. must provide access to its own transmission 

system under terms and conditions that are comparable to those the Canadian entity is 

subject to itself. 

Discussion

110. The Commission proposes 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, which are described above: a non-public utility that owns, 
Docket Nos. RM05-25-000 and RM05-17-000 - 75 – 

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.104

111. We do not propose a generic rule to implement the new FPA section 211A.105 

Rather, we will apply its provisions on a case-by-case basis, such as when a public utility 

seeks service from an unregulated transmitting utility that has not requested service under 

the public utility’s OATT and the reciprocity obligation therefore does not apply.106 

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 

 104 For non-public utilities that choose to use the safe harbor tariff, we note that its 

provisions must be substantially conforming or superior to the new pro forma OATT. A 

non-public utility that already has a safe harbor tariff may 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. 

105 We note that LPPC has committed to voluntary compliance with a set of 

guidelines for the provision of comparable service under FPA section 211A. 

106 We do, however, propose to amend our regulations to make clear that an 

applicant in a 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 a FPA section 211A order 

should be granted. See revised 18 CFR 35.28(e)(1)(ii). 
Docket Nos. RM05-25-000 and RM05-17-000 - 76 – 

of FPA section 211A. Further, as we indicate below, we expect unregulated transmission 

providers to participate in the open and transparent regional planning processes that we 

propose to order and note that, if there are complaints about such participation, we will 

address them on a case-by-case basis. 

112. We disagree with the position of the Canadian Electricity Association. EPAct 

2005 did not repeal the reciprocity obligation in Order No. 888. Rather, it granted a new 

avenue of authority to the Commission to order comparable transmission service from 

non-public utilities. We are proposing not to exercise this new authority at this time. 

Rather, we are proposing to retain our reciprocity policy, which was adopted pursuant to 

sections 205 and 206 of the FPA. By maintaining the same reciprocity requirement for 

domestic, non-public utilities as for foreign utilities doing business in the United States, 

the Commission will ensure that foreign entities will continue to be treated no less 

favorably than domestic, non-public utilities. 

V. Proposed Modifications of the OATT 

A. Consistency and Transparency of ATC Calculations 

113. In Order Nos. 888 and 889, the Commission directed transmission providers to 

offer their unused transfer capability to the market and to post the amount of ATC107 on 

OASIS. At the time those orders were issued, the Commission noted that formal methods 

did not exist for calculating ATC, but recognized that there were industry efforts 

 107 See supra note 7. 
Docket Nos. RM05-25-000 and RM05-17-000 - 77 – 

underway to develop a consistent, industry-wide method for calculating it.108 Instead of 

prescribing a specific methodology for calculating ATC in Order Nos. 888 and 889, the 

Commission encouraged the industry efforts and required that transmission providers 

base their ATC calculation methodologies on current industry practices, standards and 

criteria.109 In addition, the Commission directed transmission providers to include a 

description of their ATC calculation methodologies in Attachment C of their tariffs. 

114. Ten years later, however, although some progress has been made, the industry still 

has not developed a consistent, industry-wide methodology for evaluating ATC. In the 

intervening years, the industry, working through the North American Electric Reliability 

Council (NERC), has adopted a general definition of ATC, which establishes a basic 

methodology for evaluating ATC. NERC also has developed a set of guiding principles 

for calculating ATC and has encouraged further consistency of ATC calculation 

methodologies on a regional level. NERC defines ATC as the transfer capability 

remaining on the system for further commercial activity over and above already 

committed uses. This value is determined by deducting existing transmission 

commitments (ETC)110 (including transmission reservations, network and retail customer 

 108 Order No. 889 at 31,607. 

109 Id.

110 NERC does not have a formal definition or standard methodology for ETC. 
Docket Nos. RM05-25-000 and RM05-17-000 - 78 – 

service), capacity benefit margin (CBM),111 and transmission reliability margin (TRM)112 

from total transfer capability (TTC).113 However, NERC’s calculation methodology is 

not prescriptive; it establishes a framework for evaluating ATC, which leaves open to 

each transmission provider’s interpretation and discretion the specific algorithm, data 

inputs and assumptions needed to assess ATC.114 Consequently, transmission providers 

 111 NERC defines CBM as the amount of firm transmission transfer capability 

preserved by the transmission provider for load-serving entities, whose loads are located 

on that transmission service provider’s system, to enable access by the load-serving 

entities to generation from interconnected systems to meet generation reliability 

requirements. Preservation of CBM for a load-serving entity allows that entity to reduce 

its installed generating capacity below that which may otherwise have been necessary 

without interconnections to meet its generation reliability requirements. The 

transmission transfer capability preserved as CBM is intended to be used by the loadserving entities only in times of emergency generation deficiencies. See North American 

Electric Reliability Council, Glossary of Terms Used in Reliability Standards, (Effective 

April 1, 2005), (NERC Glossary) available at 

ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Glossary_07Feb06.pdf. 

112 NERC defines TRM as the amount of transmission transfer capability 

necessary to provide reasonable assurance that the interconnected transmission network 

will be secure. TRM accounts for the inherent uncertainty in system conditions and the 

need for operating flexibility to ensure reliable system operation as system conditions 

change. See NERC Glossary. 

113 NERC defines TTC as the amount of electric power that can be moved or 

transferred reliably from one area to another area of the interconnected transmission 

systems by way of all transmission lines (or paths) between those areas under specified 

system conditions. See NERC Glossary. 

114 See NERC, Available Transfer Capability Definitions and Determination: A 

Framework for Determining Available Transfer Capabilities of the Interconnected 

Transmission Networks for a Commercially Viable Electricity Market (1996) available at 

ftp://ftp.nerc.com/pub/sys/all_updl/docs/pubs/atcfinal.pdf. 
Docket Nos. RM05-25-000 and RM05-17-000 - 79 – 

have developed numerous ways to evaluate ATC using their own algorithms, data and 

modeling assumptions.115 

115. Although transmission providers across the Nation have developed various 

methodologies, in general, there are two main approaches to calculating ATC used in the 

industry. The first is the contract path approach, which is more commonly used by 

transmission providers in the Western Electricity Coordinating Council (WECC) 

region.116 The contract path methodology derives ATC directly from predetermined 

TTC, ETC, CBM, and TRM values derived consistent with contract path transmission 

rights. The second method is the flowgate117 approach, which is used more widely in the 

Eastern Interconnection.118 The flowgate methodology is based on physical power flow 

models. The flowgate calculation first determines AFC and then converts AFC into ATC 

and derives TTC for the OASIS posting. The differences between the two approaches 

 115 See supra note 59. 

116 See, e.g., Determination of Available Transfer Capability within the Western 

Interconnection (June 2001), available at 

http://www.wecc.biz/documents/library/procedures/ATC-apprdec01.pdf. 

117 A flowgate is a designated point on the transmission system used in the 

modeling of power flows. While NERC currently does not have a formal definition for 

AFC, the power industry commonly defines AFC as a measure of the capability 

remaining on a flowgate for future uses, after considering the effect of prior sales. 

Mathematically, the industry measures AFC as AFC = Flowgate rating – [(base case 

flow) – (impacts of existing reservations)] – Flowgate CBM –Flowgate TRM. 

118See, e.g., PJM Manual 2: Transmission Service Request (April 14, 2005), 

available at: http://www.pjm.com/contributions/pjm-manuals/pdf/m02v08.pdf 
Docket Nos. RM05-25-000 and RM05-17-000 - 80 – 

may not result in significantly different ATC values if consistent data inputs and industry 

acceptable modeling assumptions are used. Without a consistent and transparent 

approach to evaluating ATC, transmission customers will remain wary when service is 

denied and transmission providers will be the subject of suspicion and heightened 

scrutiny, especially given the increasingly congested state of the Nation’s electric grid. 

Consistency

116. Generally, transmission providers calculate ATC by creating a base model of their 

system using a set of data inputs and assumptions, which are determined by the 

transmission provider. The transmission provider uses the model to perform various 

computer simulations of the operations of its system to determine the levels of transfer 

capability available on the system. The types of data and assumptions used in the models 

include, for example, facility ratings, the operating status of facilities, and generation 

dispatch, which might be supported by history, transmission plans, or the judgment of the 

transmission provider. For example, a transmission provider could use its judgment to 

reduce a facility rating or model certain facilities as out of service, which would have the 

effect of calculating a lower TTC value. A transmission provider also may use 

generation dispatch assumptions to limit transfer capability that otherwise would have 

been available to independent generators, thereby favoring the transmission provider’s 

own generation. A transmission provider usually assumes that designated network 

resources are dispatched in economic merit order. However, a transmission provider has 

the discretion to decide which of the generators that are not designated network resources 
Docket Nos. RM05-25-000 and RM05-17-000 - 81 – 

will be modeled in-service. Assumptions like these influence the loading on transmission 

lines in the model and heavily influence the resulting ATC. Having standards in place 

that address the calculation of ATC components, data inputs, and modeling assumptions 

would help ensure non-discriminatory treatment by limiting a transmission provider’s 

ability to use discretion to the disadvantage of competitors and the market. 

117. As noted above, NERC does not have a formal definition of ETC. Without clear 

criteria for what should be included in a transmission provider’s ETC, a transmission 

customer might not know whether ETC is being over- or underestimated. For example, a 

transmission provider could set aside more capacity for native load than is realistically 

expected to occur. This could happen if a transmission provider includes in ETC excess 

capacity for a load-serving entity (such as capacity to meet generation reserve 

requirements) but then also has a CBM component in its calculation of ATC that includes 

the same capacity. A transmission provider also could overestimate its ETC by doublecounting the same transmission reservations in its ATC calculation. For example, this 

could happen if a transmission provider fails to replace a transmission reservation with 

the associated real-time schedule, and as a result does not release non-firm ATC. A 

consistent process for calculating ETC will limit the subjectivity of the transmission 

provider’s decisions and provide a more uniform method for estimating ETC. 

118. With respect to the modeling of a particular transaction, when information 

concerning the source is unknown, a transmission provider has the discretion to select 
Docket Nos. RM05-25-000 and RM05-17-000 - 82 – 

which generator(s) will be used as a source.119 There are no standards for how that 

modeling should be done and, consequently, a transmission provider could model a 

source using single or multiple generators by increasing (scaling up) their output. In 

general, modeling a transaction using multiple generators as a source is less conservative 

for the transmission system than modeling a transaction using a single generator as a 

source. Modeling a transaction using multiple generators as a source typically results in a 

higher ATC value. Conversely, when a transmission provider models a transaction using 

a single generator as a source, this can result in a lower ATC value depending on the 

location of the generator. Modeling of contingency outages used for calculating ATC is 

another area within the discretion of the transmission provider. Although the type of 

contingency, such as single contingency (n-1), is determined by governing reliability 

criteria,120 the transmission provider determines which specific contingencies will be used 

for the ATC calculation. The common industry practice is to consider the loss of each 

transmission facility at voltage 100 kV and above. However, the lack of standards 

governing transfer analysis allows the transmission provider to use its discretion to 

 119 Transmission providers do not always know the generator used as a source of 

energy provided under contracts that qualify as designated resources; the only 

requirement is that the network customer have an executed contract that commits it to 

purchase noninterruptible power. See Wisconsin Public Power Inc. v. Wisconsin Public 

Service Corp., 84 FERC ¶ 61,120 at 61,650-51 (1998). 

120 Standard TPL-001-0, Table I. Transmission System Standards – Normal and 

Emergency Conditions, NERC Reliability Standards for the Bulk Electric Systems of 

North America (effective April 1, 2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 83 – 

monitor outages only of facilities at 230 kV and above, ignoring the limitations that may 

exist for the loss of the facilities at lower voltages, such as 115 kV or 138 kV. 

Consequently, ATC values may vary substantially, with ATC being much higher when 

monitoring contingencies of facilities at 230 kV and above, and much lower while 

monitoring the loss of all facilities (voltage 100 kV and above). 

119. Furthermore, in calculating ATC, transmission providers set aside a portion of 

transfer capability in the form of CBM and/or TRM to provide for adequate generation 

reserves and account for uncertainties or contingencies, respectively. Generally, CBM is 

the amount of firm transmission transfer capability held back by the transmission 

provider so that load-serving entities, whose loads are located on the transmission 

provider’s system, can access remote generation reserve from interconnected systems in 

times of emergency generation deficiencies. Some believe it is necessary for 

transmission providers to set aside a portion of their TTC to ensure that their ties with 

other systems remain available for this purpose. There are no consistent industry-wide 

standards, however, for determining how much transfer capability should be set aside as 

CBM. There is also no common approach to whether the capacity is set aside for Native 

Load Customers, as defined in section 1.19 of the pro forma OATT, for retail load, or for 

all load-serving entities. The lack of consistent criteria and clarity with regard to the 

entity on whose behalf CBM has been set aside has the potential to result in the 

transmission provider setting aside capacity that it might not otherwise need to, thus 
Docket Nos. RM05-25-000 and RM05-17-000 - 84 – 

increasing costs for native load customers and blocking other firm uses of the 

transmission system.121 

120. Similarly, TRM is the amount of transmission transfer capability reserved by the 

transmission provider to ensure that the transmission network will be secure under a 

reasonable range of uncertainties in system conditions. Because TRM and CBM are both 

maintained in part for the loss of generators, there exists the possibility of doublecounting reliability margins for the loss of the same generation. 

121. Moreover, a transmission provider also can use more conservative inputs and 

assumptions for calculating ATC and performing system impact studies (that tend to 

minimize ATC) when it is assessing a long-term transmission service request, but use less 

conservative inputs and assumptions (that tend to maximize ATC) when it is performing 

system planning for retail native load. This creates the potential for undue discrimination 

where a transmission provider uses one set of data and assumptions to evaluate third 

party requests and another set of data and assumptions to plan its system to serve its own 

load. 

 121 The Commission has explained that the pro forma OATT requires both 

transmission customers and transmission providers using the transmission system to serve 

network load (including bundled retail native load) to designate their resources and loads 

so that the transmission customers and transmission providers would have no incentive to 

designate network resources above their needs and, in so doing, tie up valuable 

transmission capacity. Aquila Power Corp. v. Entergy Services, Inc., 90 FERC ¶ 61,260, 

reh’g denied, 92 FERC ¶ 61,064 (2000), reh’g denied, 101 FERC ¶ 61,328 (2002), aff’d

sub nom. Entergy Services, Inc. v. FERC, 375 F.3d 1204 (D.C. Cir. 2004) (Aquila). 
Docket Nos. RM05-25-000 and RM05-17-000 - 85 – 

Data Exchange Among Transmission Providers

122. The lack of a consistent ATC calculation methodology combined with limited 

coordination between transmission providers can result not only in inefficiencies but 

unjust and unreasonable terms and conditions of service, especially for a customer 

seeking contiguous transmission service from multiple transmission providers. The ATC 

values posted by a transmission provider are often inaccurate for reasons beyond the 

control of the transmission provider. A transmission provider may post ATC values in 

good faith and attempt to provide transmission service based on these values only to 

discover later that the transfer capability that it thought was available no longer exists due 

to decisions made by other transmission providers that it did not know about at the time it 

made its calculations. Accurate ATC calculation requires reliable and timely information 

about such things as load, generation dispatch, facility outages, and transactions on 

neighboring systems. Transmission providers also may apply differing assumptions and 

criteria to ATC calculations, which may produce wide variations in posted ATC values 

for the same transmission paths. All of these considerations make it difficult for an 

individual transmission provider that operates one part of an interconnected grid to 

calculate ATC accurately. 

123. This lack of communication and coordination between transmission providers of 

ATC data can also affect reliability. As discussed above, a transmission provider could 

grant transmission service without being aware of the real impact that service may have 

on an adjacent transmission provider’s system, thus degrading the reliability of the 
Docket Nos. RM05-25-000 and RM05-17-000 - 86 – 

interconnected system. Inaccurate ATC values can cause overselling of transfer 

capability, which can lead to curtailments or transmission loading relief (TLR) actions to 

avoid exceeding thermal, voltage, and/or stability limits. 

Transparency

124. As discussed, the lack of a consistent, industry-wide methodology for assessing 

ATC makes undue discrimination difficult to detect. This problem is further exacerbated 

by a lack of transparency surrounding the calculation methodology used by transmission 

providers. Although the Commission requires transmission providers to file their 

methodologies for calculating ATC in their tariffs, transmission providers often have 

responded by filing very general narrative descriptions of their calculation methodologies 

(often simply referring to the general NERC definition)122 without further specification of 

the mathematical algorithm, data inputs, and modeling assumptions used to perform the 

calculation. 

125. Other than the description of the ATC methodology provided in transmission 

providers’ tariffs, third parties often have limited access to information concerning the 

specific algorithms, data and assumptions used by transmission providers to evaluate 

their ATC, which makes it difficult to verify or challenge a transmission provider’s ATC 

calculations. The Commission requires each transmission provider to calculate and post 

 122 See, e.g., the OATTs of Aquila, Inc., Southern, and Tucson Electric Power 

Company. 
Docket Nos. RM05-25-000 and RM05-17-000 - 87 – 

ATC and TTC values for each posted path.123 Transmission providers also are required 

to make publicly available, on request, all data used to calculate ATC and TTC for any 

constrained path.124 Additionally, transmission providers are required to make publicly 

available, on request, system planning studies or network impact studies performed for 

customers to determine network impacts. Furthermore, subsequent to Order Nos. 888 

and 889, the Commission required each transmission provider to post (and update) the 

CBM value for each path for which it already posts ATC and TTC, as well as a narrative 

explanation of its CBM practices. 125 

126. Yet, despite these requirements, third parties often are unable to gain access to 

sufficient information surrounding a transmission provider’s ATC calculation 

methodology. As a preliminary matter, we note that while the OASIS requirements 

regarding the availability of information related to ATC and TTC calculations are still in 

effect, they have been affected by restrictions that have been placed upon the availability 

 123 See 18 CFR 37.6 (b) (2005). A posted path is defined as any control area to 

control area interconnection; any path for which service is denied, curtailed or interrupted 

for more than 24 hours in the past 12 months; and any path for which a customer requests 

to have ATC or TTC posted. Id. 37.6 (b)(1)(i). 

124 Id. 37.6 (b)(2)(ii). A constrained posted path is defined as any posted path 

having an ATC value less than or equal to 25 percent of TTC at any time during the 

preceding 168 hours or for which ATC has been calculated to be less than or equal to 

25 percent of TTC for any period during the current hour or the next 168 hours. Id. 

37.6 (b)(1)(ii). 

125 Capacity Benefit Margin in Computing Available Transmission Capacity, 

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

of critical energy infrastructure information (CEII) in the interest of national security.126 

Therefore, system planning and network impact studies and models typically are no 

longer available on a transmission provider’s OASIS. Furthermore, transmission 

customers are often unable to access other information such as load flow base cases and 

associated files. In sum, although existing Commission regulations are intended to 

provide a certain level of transparency, this transparency is undermined by a number of 

factors, including the absence of detailed descriptions of the data inputs, assumptions, 

and criteria used to determine the data included in ATC calculations, as well as the 

inability of customers to access certain of this data because of, among other reasons, 

security concerns. 

Recent Industry Efforts to Improve the Consistency and 

Transparency of ATC Calculations

127. The industry recently has taken some steps to address the lack of consistency and 

transparency in the way ATC is calculated. NERC formed a Long-Term AFC/ATC Task 

Force to review NERC’s standards on ATC, which issued a final report in 2005 (NERC 

Report)127 that made recommendations for greater consistency and greater clarity in the 

 126 See Critical Energy Infrastructure Information, Order No. 630, 68 FR 9857 

(Mar. 3, 2003), FERC Stats. & Regs. ¶ 31,140 (2003), order on reh’g, Order No. 630-A, 

68 FR 46456 (Aug. 6, 2003), FERC Stats. & Regs. ¶ 31,147 (2003), order on 

clarification, Order No. 662, 70 FR 37031 (Jun. 28, 2005), FERC Stats. & Regs. ¶ 31,189 

(2005); see also 18 CFR 388.113 (2005). 

127 See supra note 115. 
Docket Nos. RM05-25-000 and RM05-17-000 - 89 – 

calculation of ATC. The task force also recommended greater communication and 

coordination of ATC information to ensure that neighboring entities exchange relevant 

information. Based on the recommendations in the NERC Report, NERC has two 

Standards Authorization Request (SAR) proceedings underway to revise the standards on 

ATC. The first SAR proceeding proposes changes to the existing standards on ATC to, 

among other things, further establish consistency (on a regional basis) in the calculation 

of ATC and to increase the clarity of each transmission provider’s ATC calculation 

methodology. The second SAR proceeding proposes certain changes to NERC’s existing 

standards on the ATC components of CBM and TRM. This proceeding also calls for 

greater regional consistency and transparency in how CBM and TRM are treated in 

transmission providers’ ATC calculations. Also, based on the recommendations in the 

NERC Report, the North American Energy Standards Board (NAESB) has a proceeding 

underway to develop business practice standards to enhance the processing of 

transmission service requests, which use TTC, ATC and/or AFC. 

128. Following the release of the NERC Report, the Commission issued the ATC 

NOI128 seeking comments on the contents of the NERC Report. More specifically, the 

Commission sought comments on the NERC Report’s recommendations on areas in 

which CBM and TRM could be more specific and whether these recommendations go far 

enough in promoting a common CBM and TRM methodology within each region. The 

 128 Supra note 9. 
Docket Nos. RM05-25-000 and RM05-17-000 - 90 – 

Commission also sought comments on the definitions of ATC, AFC, CBM and TRM. 

The Commission also solicited comments on the advisability of revising and 

standardizing ATC, AFC, TRM and CBM values. In addition, the Commission sought 

comments on the advisability of developing interconnection-wide standards for the 

Eastern Interconnection and WECC. Finally, the Commission asked for comments on the 

most expeditious way to obtain industry-wide standards for ATC calculations. 

129. Furthermore, in the NOI, the Commission sought comments on whether undue 

discrimination is most likely to occur in areas such as ATC calculation where the 

transmission provider retains discretion as to how to implement a particular tariff 

provision. 

Comments

 Comments on Consistency

130. Many commenters express general support for some level of increased consistency 

in ATC calculations.129 Some commenters urge the Commission to develop a consistent, 

industry-wide methodology for calculating ATC.130 Constellation asserts that although 

transmission providers need to be innovative and flexible in many respects, a requirement 

 129 E.g., Alcoa, Ameren, AWEA, Calpine, Constellation, Cottonwood ATC NOI 

Comment, ELCON, Exelon, FTC ATC NOI Comment, Midwest ISO ATC NOI 

Comment, Midwest SATS, New York Commission ATC NOI Comment, North Carolina 

Commission, Occidental, South Carolina E&G, TAPS, and TransAlta. 

130 E.g., Alcoa, AWEA, Constellation, Exelon, Occidental, and Renewable 

Energy. 
Docket Nos. RM05-25-000 and RM05-17-000 - 91 – 

that all transmission providers use the same methodology to determine ATC would not 

only remedy the lack of clarity that surrounds these calculations and reservations, but 

would provide regulatory certainty and assist transmission customers in predicting the 

outcome of transmission service requests. This, in turn, Constellation suggests, would 

expand the commercial opportunities for transmission customers. According to Alcoa, 

AWEA and Renewable Energy, the industry-wide methodology should be a flow-based 

methodology, rather than a contract path methodology because they believe that a flowbased analysis provides a more realistic view of actual system usage and results in a more 

accurate assessment of ATC. Exelon further suggests that this uniform methodology 

should also apply to all transmission providers, including RTOs. 

131. Other commenters argue against a one-size-fits-all approach, but rather express a 

preference for greater uniformity at a regional level to recognize regional differences. 131 

These commenters suggest that due to differences in transmission systems or regions, it 

may not be practical or possible to standardize the ATC calculation methodology on an 

industry-wide basis. For example, Powerex cautions that nationwide standardization may 

not take into account the unique characteristics of particular systems or regions, such as 

the differences attributable to the West’s contract-path model and the East’s flow-based 

 131 E.g., Alberta Intervenors, APPA, Bonneville, International Transmission, 

ISO/RTO Council, LDWP, MidAmerican, Nevada Companies, Powerex, Progress 

Energy, Public Generating Pool, Public Power Council, Salt River, Santa Clara, 

Snohomish, Tacoma Power, TANC, and TDU Systems. 
Docket Nos. RM05-25-000 and RM05-17-000 - 92 – 

model, as well as differences attributable to the primarily hydro-based systems in the 

Pacific Northwest.132 Similarly, TANC argues that flowgate terminology and application 

in ATC calculation should not be required in the West because it does not adequately 

represent the nature of the many transmission constraints in the West. Other commenters 

caution that too much uniformity of the ATC calculation methodology could have an 

adverse effect on grid reliability.133 In addition, some commenters urge the Commission 

not to adopt an ATC methodology that is so prescriptive that it inhibits new or better 

practices or imposes a wholesale revision of accepted market designs and processes that 

are working within established markets.134 

132. Several commenters argue against any efforts to further standardize ATC 

calculations.135 In its comments filed in the ATC NOI proceeding, LDWP asserts that the 

alleged problems with ATC are overstated. Moreover, it argues, the benefits of 

squeezing additional ATC from existing systems have not been established given that 

transmission customers can already request any capacity they need regardless of the 

posted ATC and transmission providers are required to make a good-faith effort to 

 132 Accord LDWP ATC NOI Comment, Public Power Council, Salt River, 

Snohomish, Tacoma, and TANC. 

133 E.g., NERC ATC NOI Comment, Public Power Council, and TVA. 

134 E.g., ISO/RTO ATC NOI Comment and Powerex. 

135 E.g., Cinergy, EEI, LG&E, LDWP ATC NOI Comment, National Grid, PPL, 

Public Generating Pool, San Diego G&E, Southern, TVA, and Xcel. 
Docket Nos. RM05-25-000 and RM05-17-000 - 93 – 

evaluate each request. Several commenters argue that the circumstances of individual 

transmission customers vary and often ATC calculations rely on the individual 

transmission provider’s knowledge of its facilities and system conditions.136 For 

example, Southern contends that too many factors go into the calculation of ATC to make 

the adoption of a static set of standards feasible. In fact, Southern and EEI maintain, 

standardization of ATC calculations is inconsistent with maintaining reliability because 

the circumstances of transmission providers vary significantly, and they must operate 

their systems based on their specific circumstances. In addition, LG&E maintains that 

standardizing ATC will not necessarily eliminate the need for TLR procedures to deal 

with load forecast errors and unplanned generation and transmission outages. 

Furthermore, some commenters argue that increased uniformity could impose significant 

costs upon utilities.137 

133. Some commenters urge the Commission to increase the consistency of the 

elements of the ATC calculation, such as the kind of data inputs that transmission 

providers consider when evaluating ATC – including load levels, generator outage 

information, transmission outage information and generation dispatch information.138 

Exelon also urges the Commission to establish the assumptions that transmission 

 136 E.g., Southern and TVA. 

137 E.g., International Transmission and LG&E. 

138 E.g., Exelon and TDU Systems. 
Docket Nos. RM05-25-000 and RM05-17-000 - 94 – 

providers use in their ATC methodologies – such as how transmission reservations are 

accounted for and which reservations to model. Exelon also cites an example of 

modeling transaction counterflows, noting that uniform rules for data inputs are needed to 

ensure that transaction counterflows are modeled identically in both the planning and 

ATC/AFC calculation processes. In addition, commenters urge the Commission to 

establish the procedures for determining ATC (and its components) and to require a 

transmission provider to show that it has properly followed all required procedures.139 

Among other things, commenters suggest that the Commission should establish how 

frequently ATC is calculated, how frequently inputs are updated, require transmission 

providers to determine AFC instead of ATC, and require transmission providers to 

recognize all third-party flowgates that are requested to be monitored. In addition, 

several commenters state that the Commission should require that the methodology and 

inputs for ATC calculations be consistent with the transmission provider’s planning or 

operating criteria.140 

134. Several commenters urge the Commission to allow the industry, working through 

NERC and NAESB, to complete efforts already underway to further increase consistency 

 139 E.g., Ameren and Exelon. 

140 E.g., Exelon, ISO/RTO ATC NOI Comment, MISO, and NERC. 
Docket Nos. RM05-25-000 and RM05-17-000 - 95 – 

of ATC (and its components), as well as certain related business practices.141 However, 

many of these commenters urge the Commission to give the industry, working through 

these organizations, specific guidance on what issues to decide and the parameters for the 

discussions.142 Furthermore, commenters state that the Commission should establish a 

date certain for completion of these industry efforts,143 and should also take an active role 

in the process.144 

135. Other commenters suggest that the Commission should require that an 

independent entity develop and/or monitor a transmission provider’s ATC methodology 

and its ATC calculations.145 For example, Constellation states that it does not believe 

that the solution is to prohibit the transmission provider entirely from exercising its 

discretion, but instead to require transmission providers to retain an independent entity 

that can perform certain functions on a consistent, unbiased basis. In addition, the 

 141 E.g., Ameren, APPA ATC NOI Comment, Duke, EEI, Exelon, International 

Transmission Company ATC NOI Comment, ISO/RTO Council ATC NOI Comment, 

KCP&L, MidAmerican ATC NOI Comment, MISO ATC NOI Comment, Progress 

Energy, Southern, TAPS, TDU Systems, TransAlta, and WestConnect ATC NOI 

Comment. 

142 E.g., APPA ATC NOI Comment and International Transmission ATC NOI 

Comments. 

143 E.g., Duke and Exelon. 

144 E.g., APPA ATC NOI Comment, TAPS, and TransAlta. 

145 E.g., Arkansas Commission, Calpine, Constellation, EPSA, New York 

Commission, Occidental, and TDU Systems. 
Docket Nos. RM05-25-000 and RM05-17-000 - 96 – 

Arkansas Commission asserts that section 1281 of EPAct 2005146 gives the Commission 

the authority to require the use of an independent coordinator of transmission to provide 

independent and verifiable transparency over critical Order No. 888 functions, such as 

ATC calculations. 

136. Several commenters specifically address the lack of consistency in the industry on 

the definition and use of CBM and TRM. For example, TAPS notes that NERC does not 

require any transmission provider to reserve CBM. In addition, TAPS states, even in 

those regions that use CBM, there is often no regional methodology; it is up to the 

vertically integrated transmission provider to determine whether it wants to reserve CBM 

at all and at which interfaces, with no effective review of that determination. TAPS also 

states that TRM should be clearly defined and, if truly required for reliability, then all 

transmission providers should reserve it. According to TAPS, the Commission should 

define TRM in a manner that leaves no discretion as to whether, where, and how much 

capacity to set aside. EPSA also notes that there is a disconnect between the planning 

and expansion processes and the assumptions transmission providers use to calculate 

CBM and TRM. 

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

824t), which concerns electricity market transparency rules. 
Docket Nos. RM05-25-000 and RM05-17-000 - 97 – 

137. TANC states that the Commission should closely examine the necessity of CBM 

in ATC calculations. Bonneville argues that there should only be one commercial margin 

instead of multiple margins (TRM, CBM, and others). 

Comments on Data Exchange among Transmission Providers

138. Several commenters argue that the Commission should establish standards for 

resolving seams issues between transmission providers where each transmission provider 

uses a different methodology for calculating ATC.147 Constellation and BC Transmission 

assert that when different transmission providers have different methods for determining 

ATC, this can lead to inefficiencies, including market confusion, lost sales/purchase 

opportunities, and unnecessary curtailments. 

139. Commenters identify various elements of the ATC calculation methodology that 

they argue should be more consistent. For example, BC Transmission states that some of 

the elements that are calculated differently at the seams include the level of TRM, the 

level of CBM, the approach regarding the sale (or not) of TRM as non-firm capacity, 

assumptions regarding controlling interchange and assumptions regarding operating 

conditions. Similarly, MidAmerican in its response to the ATC NOI suggests that greater 

coordination is needed on partial path review, policies for decrementing AFC and 

redispatch policies. For example, MidAmerican references problems associated with 

 147 E.g., BC Transmission, Constellation, Exelon, NY Transmission, Renewable 

Energy, and TDU Systems. 
Docket Nos. RM05-25-000 and RM05-17-000 - 98 – 

coordination between transmission providers on partial path treatment. Specifically, 

when transmission service involves a path across multiple systems, a given flowgate may 

be evaluated several times by various providers on the transmission path. Because of a 

lack of coordination between these providers, AFC on the flowgate may be decremented 

multiple times for the same transmission service request, and service may be denied even 

when the true available capacity on the flowgate is sufficient to allow the request to be 

granted. Exelon also states that certain data inputs must be coordinated across all 

transmission providers in an interconnection including load levels, transmission outages, 

generation outages and generation dispatch. In addition, Exelon states, the Commission 

should establish how transmission providers account for transmission reservations in an 

ATC/AFC calculation. 

140. Moreover, NY Commission suggests that this problem goes beyond the nonindependent transmission providers. According to NY Commission, in order for RTOs to 

properly determine tie flow limits, they need access to certain information from the 

control region on the other side such as load levels and distributions, generator dynamic 

capability and expected outputs, phase shifter positions and standard contingencies 

required by that control area. In addition, NY Commission states, these inputs need to be 

updated daily. 

141. Finally, Alcoa states that the potential for underestimating ATC is likely another 

consequence of the fundamental conflict between the contract path model and the 

electricity path model of contracting for electric energy. According to Alcoa, outside of 
Docket Nos. RM05-25-000 and RM05-17-000 - 99 – 

ISO/RTO systems, utilities may not have enough data available to compute ATC, since 

they may not be able to accurately complete all relevant parallel path transactions. 

Comments on Transparency

142. Commenters are overwhelmingly in favor of greater transparency in the ATC 

calculation methodology to provide more assurance that a transmission provider is not 

performing its ATC calculations in an inconsistent or unduly discriminatory manner.148 

EEI suggests that transmission providers could make their base case load flow studies on 

which they base their calculation of ATC available to transmission customers, subject to 

security and confidentiality protections. Other commenters state that greater 

transparency could be achieved through the imposition of additional posting requirements 

on OASIS.149 These commenters argue that the Commission should require transmission 

providers to post their discrete methodologies and algorithms for evaluating ATC, as well 

as their transmission modeling information and their various assumptions. Commenters 

further suggest that transmission providers should be required to provide information 

 148 E.g., Alcoa, Ameren, APPA, Calpine, CEOB, Cinergy, Constellation, 

Cottonwood, Duke, EEI, ELCON, HQ Energy, LDWP, MidAmerican, Midwest ISO, 

Midwest SATs, Powerex, PPL, Progress Energy, Public Generating Pool, Public Power 

Council, Salt River, Southern, TANC, TAPS, TDU Systems, TransAlta, and TVA. 

149 E.g., Calpine and PPL. 
Docket Nos. RM05-25-000 and RM05-17-000 - 100 – 

regarding planned outages, and to ensure consistent treatment of outage information 

between control areas.150 

143. In its reply comments, Southern acknowledges that greater transparency would 

reduce concerns of undue discrimination, but cautions the Commission against imposing 

unnecessary and duplicative posting requirements and notes that much of the information 

that commenters have asked the Commission to make transparent is in fact already 

publicly available through a variety of sources. 

144. In addition, some commenters urge the Commission to impose meaningful 

reporting requirements.151 In this regard, Constellation asserts that the Commission 

should modify the pro forma OATT to require that transmission providers post 

systematic, timely and accurate reporting of certain service metrics such as transaction 

requests approved, rejected, confirmed, and curtailed. Similarly, Cottonwood states that 

transmission providers should be required to provide information detailing why a 

particular transmission request was denied and whether there are other available 

alternatives. In addition, several commenters argue that transmission providers also 

should be required to post their relevant business practices, operating standards, protocols 

and internal guidelines that affect transmission service.152 TDU Systems also urge the 

 150 E.g., H.Q. Energy and Powerex. 

151 E.g., Constellation, Cottonwood, and TDU Systems. 

152 E.g., Powerex and TransAlta. 
Docket Nos. RM05-25-000 and RM05-17-000 - 101 – 

Commission to require transmission providers to explain why transactions are allowed to 

flow even when the posted ATC value was zero. 

145. EPSA argues that capacity is unnecessarily held from the market when 

transmission providers reserve excessive amounts for their native load and when they fail 

to make capacity available through redispatch. EPSA states, however, that there is no 

way of knowing whether there is a hoarding problem because there is no requirement to 

post the necessary real time information on transmission utilization, and recommends a 

requirement to post such information. Powerex contends there is an incentive for 

transmission providers to hoard because grandfathered or other firm rights held by the 

transmission provider to serve native load are subsequently used for wholesale marketing 

purposes. It further states, however, that evidence of anticompetitive practices is difficult 

to obtain because of a lack of transparency. Powerex supports increased requirements for 

both uniform and transparent ATC calculation. 

146. Several commenters urge the Commission to establish compliance review 

procedures and impose sanctions for violations to ensure that transmission providers are 

accountable for ensuring that their ATC calculations are correct.153 In its response to the 

ATC NOI, Cottonwood states that the Commission should develop specific tests 

(benchmarks) to monitor transmission providers’ performance. In addition, HQ Energy 

 153 E.g., Cottonwood ATC NOI Comment, ELCON, HQ Energy, NRECA, 

Occidental, and Powerex. 
Docket Nos. RM05-25-000 and RM05-17-000 - 102 – 

states that the Commission should conduct periodic reviews of whether non-independent 

transmission providers have properly calculated and allocated ATC. ELCON states that 

the Commission should place the burden of proof to depart from its ATC methodology on 

the transmission provider and include specific penalties in the tariff for transmission 

providers that are found to be in violation. 

147. HQ Energy and Powerex also state that the Commission should require 

transmission providers to ensure that staff is available at all times to respond to customer 

inquiries regarding real-time transactions. 

Discussion

148. We propose to address the potential for remaining undue discrimination in the 

determination of ATC by requiring industry-wide consistency and transparency of certain 

definitions, data, modeling assumptions and components of ATC. We propose to provide 

general guidance regarding the aspects of ATC calculation that we believe should be 

more consistent and direct public utilities, working through NERC and NAESB, to use 

our guidance to revise the relevant standards and business practices. In addition, we 

propose to require increased detail in the pro forma OATT regarding the method of 

calculating ATC and to amend our OASIS regulations to require increased transparency. 
Docket Nos. RM05-25-000 and RM05-17-000 - 103 – 

149. Though NERC and NAESB currently are working on certain proposals to address 

the problems we have identified,154 we are concerned that without guidance, direction 

and a firm deadline, these industry developments may not succeed due to other 

conflicting priorities. We believe that the existing NERC and NAESB processes are 

well-suited to achieving greater consistency in ATC calculations. It is our expectation 

that NERC and NAESB will expand on the work they have already undertaken to achieve 

the goals we propose to set out for them. 

150. We propose to take this action pursuant to our obligation under FPA section 206 to 

remedy undue discrimination in the provision of transmission service. Transmission 

providers in general enjoy substantial discretion in establishing and interpreting the 

specific algorithms, data, and assumptions needed to assess ATC. Though we do not 

believe it is possible or necessary to entirely eliminate discretion, unchecked discretion 

affords a transmission provider the ability and opportunity to discriminate in its favor 

(and its affiliate’s favor) against third parties in how it calculates and allocates ATC and, 

therefore, may be unjust, unreasonable, unduly discriminatory and preferential. 

Transmission providers have an incentive to understate ATC on transmission paths that 

 154 We understand that two NERC standard authorization requests related to ATC/ 

TTC/AFC and CBM/TRM were approved earlier this year, and that drafting of the 

standards’ revision is underway. We further understand that NAESB has a concurrent 

drafting effort underway for associated business practices that will follow a coordinated 

path with the NERC process. See http://www.nerc.com/~filez/standards/MOD-V0-

Revision.html. 
Docket Nos. RM05-25-000 and RM05-17-000 - 104 – 

would be valuable to power sellers that are competitors to the transmission providers’ 

own (or their affiliates’) power sales. Where transmission congestion exists, the 

methodology for calculating ATC will effectively determine whether competitors have 

access to the transmission grid, and the lack of any consistent methodology for 

calculating ATC gives transmission providers excessive discretion in making this 

determination. 

151. The lack of consistency and detail in the determination of ATC can facilitate 

undue discrimination in a variety of ways. Transmission providers may use generation 

dispatch assumptions that result in limited capacity being available to merchant 

generators. They also may use different inputs and assumptions for purposes of 

calculating ATC for third parties than they do for system planning for retail native load. 

As noted above, a transmission provider could reduce a facility rating or model certain 

facilities as out of service, which would have the effect of underestimating TTC. In 

determining ETC, transmission providers have discretion to determine the capacity 

needed and set aside for native load usage. Each of these exercises of discretion has a 

significant effect on ATC. 

152. The lack of transparency into how a transmission provider calculates and allocates 

its ATC (including all assumptions and data inputs) makes it difficult to detect 

discriminatory behavior. This lack of transparency frustrates and increases the costs of 

compliance and enforcement efforts. Many transmission providers have urged the 
Docket Nos. RM05-25-000 and RM05-17-000 - 105 – 

Commission to provide greater clarity in the rules for OATT service,155 particularly given 

the threat of the Commission’s new civil penalty authority. 

153. In addition to our preliminary finding that the lack of consistent, industry-wide 

ATC calculation standards is unjust and unreasonable under FPA section 206, we believe 

that it poses a threat to the reliable operation of the bulk-power system. A transmission 

provider needs to know how much electricity its system can carry. The lack of a 

consistent, industry-wide methodology for evaluating ATC and the lack of data sharing 

among transmission providers often leads to problems in determining the appropriate 

ATC value. Despite a transmission provider’s good faith attempt to calculate and post 

accurate ATC levels, it can find that transmission that it thought was available on its 

system no longer exists because it was unaware of decisions by other transmission 

providers. This, in turn, can threaten the reliable operation of the interconnected 

transmission system.156 

 155 E.g., Ameren, APPA ATC NOI Comments, Duke, EEI, Exelon, International 

Transmission Company ATC NOI Comments, ISO/RTO Council ATC NOI Comments, 

KCP&L, MidAmerican ATC NOI Comments, MISO ATC NOI Comments, Progress 

Energy, Southern, TAPS, TDU Systems, TransAlta, and WestConnect ATC NOI 

Comments. 

156 According to NERC, “the lack of standardization and more significantly, 

limited coordination can negatively impact both the market, through the need for a large 

number of [TLR] actions (or curtailments in WECC) and, on occasion, reliability when 

even the use of TLRs provides insufficient relief on some critical interfaces.” See NERC 

Report at 1. 
Docket Nos. RM05-25-000 and RM05-17-000 - 106 – 

154. As a result of reliability effects of inconsistent ATC calculations, our proposal for 

greater consistency and transparency also is supported by our new authority under 

section 215 of the FPA, which gives the Commission jurisdiction to certify an Electric 

Reliability Organization (ERO) and to approve reliability standards that are just, 

reasonable, not unduly discriminatory or preferential, and in the public interest. The 

Commission also has authority to order the ERO to submit a reliability standard that the 

Commission considers appropriate to implement FPA section 215.157 On April 4, 2006, 

NERC submitted an application to be certified as the ERO, as well as proposed reliability 

standards.158 In this NOPR, we direct our guidance to public utilities and recommend 

that they implement our direction by working with NERC. However, this is not intended 

to prejudge the outcome of the ERO proceeding. Though the Commission will act 

independently on the reliability standards proposed by NERC in Docket No. RM06-16-

000, we believe it is prudent to provide our guidance now on NERC’s reliability 

standards related to ATC by providing specific direction on what should be more 

consistent and a timeframe for completion of NERC’s efforts.159 As we indicated above, 

the lack of consistency, data exchange and transparency in ATC calculations not only can 

 157 Section 215(d)(5). 

158 See Docket Nos. RR06-1-000 and RM06-16-000. 

159 In this NOPR, we direct our guidance to NERC, though the reliability standards 

relating to ATC ultimately will be adopted by the ERO. 
Docket Nos. RM05-25-000 and RM05-17-000 - 107 – 

increase the opportunities for undue discrimination but also can threaten reliability. We 

therefore believe that Commission action pursuant to FPA section 215 may be 

appropriate on reliability standards related to ATC calculation. Any action on these 

reliability standards that is taken in Docket No. RM06-16-000 (the ERO standards 

rulemaking) will be coordinated and consistent with our determinations regarding ATC 

calculation in this proceeding.160

Consistency

155. The Commission proposes to require public utilities, working through NERC, to 

develop the standards we set forth below within 6 months of the final rule in this 

proceeding. Consistent with NERC’s existing efforts, we propose to require the 

development of standards for: (1) ATC/AFC, TTC/Total Flowgate Capacity (TFC), 

ETC, CBM, and TRM calculation methodologies, (2) data inputs, (3) modeling 

assumptions, (4) ATC calculation frequency, and (5) data exchange and coordination 

processes. We further propose to require public utilities, working through NAESB, to 

work with NERC to identify the appropriate business practices to complement the 

standards developed by NERC. We discuss below each of the elements for which we 

propose to require more consistency. We seek comment on these elements of the ATC 

 160 We note that Commission staff recently released a preliminary assessment of 

the proposed ATC-related reliability standards, stating that they “may result in 

unnecessary regional variations not justified by technical differences and inconsistent 

applications.” Staff Preliminary Assessment of the North American Reliability Council’s 

Proposed Mandatory Reliability Standards at 80 (May 11, 2006). 
Docket Nos. RM05-25-000 and RM05-17-000 - 108 – 

calculation and, in particular, whether certain elements are more susceptible to further 

consistency than others and whether certain elements should be prioritized over others 

because they represent the source of most disputes between transmission providers and 

customers. We recognize the need to focus on those elements of the ATC calculation that 

are most susceptible to further consistency and most important in terms of eliminating 

opportunities for undue discrimination. 

156. The Commission recognizes that transmission providers use several basic types of 

ATC calculation methodologies (with various permutations), and does not believe that a 

single ATC calculation methodology must be applied by all transmission providers.161 

However, we agree with commenters who argue that the amount of discretion in the 

existing ATC calculation methodologies gives transmission providers the ability and 

opportunity to unduly discriminate against third parties. Accordingly, we propose to 

achieve greater consistency in ATC calculations by directing the development of 

consistent definitions of the components of ATC, as well as consistent data inputs, data 

exchange and coordination protocols, and modeling assumptions, as discussed further 

below. We believe that this level of consistency will go a long way toward producing 

 161 For example, there are two primary ATC calculation methodologies: the 

contract path approach and the flowgate approach. See generally P 115. However, the 

ATC values that result from application of either method should largely be the same if 

consistent data inputs and modeling assumptions are used. 
Docket Nos. RM05-25-000 and RM05-17-000 - 109 – 

more coherent and uniform determinations of ATC across a region, thereby helping to 

eliminate the potential for undue discrimination.162 

157. We propose to direct public utilities, working through NERC, to develop 

consistent practices for TTC/TFC calculation methodologies. We recognize that the 

NERC reliability regions have historically calculated transfer capability using different 

approaches.163 However, we expect that guidelines can be developed for the calculation 

of transfer capability that use a common approach to model power transfers. In addition, 

we believe that the criteria used for identifying flowgates and determining TTC/TFC can 

be more consistent. 

158. The Commission believes that the lack of consistency of ETC permits too much 

discretion in determining how much capacity a transmission provider sets aside for native 

load, including its network customers. We believe that the development of an industrywide methodology can limit this discretion. Therefore, we propose to require the 

development of a consistent methodology for determining the capacity needed and set 

aside for native load usage. In addition, we propose that accounting for transmission 

reservations in an ATC/AFC calculation also should be more consistent. Presently, there 

 162 As discussed further below, for consistency to be fully effective, it should be 

coupled with increased transparency. As such, we also propose greater transparency 

below. 

163 One approach models power transfers by scaling up/down the load, a second 

approach scales generation up/down, and yet another approach uses a combination of 

changes in load and generation. 
Docket Nos. RM05-25-000 and RM05-17-000 - 110 – 

are two main methods in use. One method models all “appropriate reservations”164 in the 

power flow base case model. The other method models only those reservations that are 

expected to be actually scheduled and accounts for others by decrementing flowgate 

AFC. It is important for consistency to use the same calculation technique when 

modeling these types of reservations. Therefore, we propose that public utilities, working 

through NERC, establish and specifically identify which reservations they use in 

determining ETC. 

159. The Commission has previously addressed the lack of a consistent industry-wide 

methodology for determining CBM. Following a two-day technical conference, the 

Commission held in the CBM Order165 that transmission providers continue to wield 

significant latitude in interpreting how CBM is determined. The Commission directed 

that the CBM set-aside be more transparent, more accurate, and more widely available.166 

We remain concerned, however, that transmission providers have preferential access to 

the interface capacity that is set aside. This interface capacity is paid for by all 

transmission customers whether or not they receive a benefit from the set-aside. In 

 164 “Appropriate reservations” takes into account the time frame (e.g., yearly, 

monthly) and ATC product (e.g., firm, non-firm) being calculated. 

165 Capacity Benefit Margin in Computing Available Transmission Capacity, 

88 FERC ¶ 61,099 (1999) (CBM Order). 

166 CBM Order at 61,237-38. 
Docket Nos. RM05-25-000 and RM05-17-000 - 111 – 

general, we believe that the latitude associated with CBM undermines the certainty and 

transparency that is needed for non-discriminatory, open-access transmission service. 

160. The current pro forma OATT offers two means of reserving transfer capability, 

either of which implicitly provides some financial discipline to overreservations. The 

first is the requirement to designate a network resource on the other side of the interface 

and assume the associated financial responsibility of either owning the resource or 

executing a firm power purchase agreement. The other is to contract for firm point-topoint service on the interface, which requires the payment of a point-to-point reservation 

charge. In either case there is a disincentive to reserving transfer capability simply to 

prevent someone else from using it on a firm basis. With these processes in mind, the 

Commission has identified three possible options to provide the necessary certainty, 

transparency, and financial discipline necessary to remedy the potential for undue 

discrimination associated with inappropriate ATC set-asides for CBM. These options 

need not be mutually exclusive. 

161. One option is to require that clear standards be developed for how the CBM value 

should be determined and allocated across transmission paths, and for which customers 

CBM should be used.167 Consistent with the standards development process that is 

already in progress, we propose that these standards specify how CBM should be 

 167 NERC has already contemplated developing a standard to address CBM issues. 

See http://www.nerc.com/~filez/standards/MOD-V0-Revision.html. 
Docket Nos. RM05-25-000 and RM05-17-000 - 112 – 

reserved to allow any load-serving entity to meet generation reliability criteria on a 

nondiscriminatory basis. In addition, we propose that NERC specify emergency 

generation deficiency conditions during which a load-serving entity will be allowed to 

use the transfer capability reserved as CBM. We believe that CBM should be reserved 

only when there is insufficient local generation capacity to meet generation reliability 

standards, and it should always have a zero value in the calculation of non-firm ATC. 

162. Another approach may be to develop a specific charge for setting aside ATC for 

CBM. This approach would treat CBM as a service that would be available to customers 

serving load within the transmission provider’s service area. To do this, the Commission 

would propose that an entity for which transfer capability has been set aside to meet 

generation reliability criteria be charged a separate rate for this service. We seek 

comment on this proposal to charge a separate rate, as well as comment on the potential 

impacts on overall rates and revenues. We also seek comment on whether there are 

credible situations in which the proposal would not be feasible. Commenters are 

encouraged to provide specific examples. 

163. A third option may be to eliminate CBM and replace it with specific transfer 

capability reservations associated with designated network resources. In several cases, 

the Commission addressed instances when transmission providers had taken advantage of 

their ability to preserve interface capability to serve their own load while limiting the 

ability of competing suppliers to access customers on their systems. In these orders, the 

Commission position was that if a utility wanted to use firm transmission capacity on an 
Docket Nos. RM05-25-000 and RM05-17-000 - 113 – 

interface to serve its native load, it was required to designate a network resource 

associated with that capacity on the other side of the interface pursuant to the 

requirements of the pro forma OATT.168 Specifically, the Commission stated that the pro 

forma OATT requires the transmission provider to designate all network resources, 

including those acquired for the purpose of meeting generation reserves, in the same 

manner as network customers do.169 The retention of this obligation would require the 

transmission provider to replace any existing set-aside of firm transfer capability as CBM 

with reservations for specific designated resources. We seek comment on the 

reasonableness of eliminating CBM and any impacts on the reliable operation of the 

transmission system. Commenters are encouraged to provide specific examples of 

transmission providers that currently do not use CBM and, alternatively, conditions under 

which CBM must be used. We also ask for comments on how eliminating CBM would 

affect the ability of load-serving entities to meet existing generation reliability adequacy 

requirements. 

164. The Commission proposes that public utilities, working through NERC, develop 

clear standards for how TRM is determined, allocated across transmission paths, and 

 168 See Aquila supra note 121; see also Morgan Stanley Capital Group v. Illinois 

Power Co., 83 FERC ¶ 61,204, clarified, 83 FERC ¶ 61,299 (1998), order on reh’g, 

93 FERC ¶ 61,081 (2000). 

169 Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public Service Corp., 

83 FERC ¶ 61,198 at 61,857-58 (1998). 
Docket Nos. RM05-25-000 and RM05-17-000 - 114 – 

used. In addition, we propose to require that the standards ensure that there will be no 

contingency double-counting when calculating TRM, TTC and CBM. We also propose 

that the standards developed should specify the uncertainties that are accounted for in 

TRM and the methods used to determine their impacts on TRM values. The Commission 

proposes that TRM can be used to accommodate uncertainties such as: (1) load forecast 

and load distribution error, (2) variations in facility loadings, (3) uncertainty in 

transmission system topology, (4) loop flow impact, (5) variations in generation dispatch, 

including intermittent resources, (6) automatic sharing of reserves, and (7) other 

uncertainties identified through the NERC forums. 

165. The Commission acknowledges that accurate data and system models are essential 

to accurately simulate the performance of the electric system when calculating ATC. The 

data and models used by the transmission provider should be consistent, to the maximum 

extent practicable, with the data and models used for the planning, operation, and 

expansion of the transmission system. While NERC’s current ATC-related standards 

(MOD-001- MOD-009) require that steady state and dynamic data be submitted and that 

steady state and dynamic system models be prepared, there is no requirement to 

periodically benchmark these models and appropriately modify them against actual 
Docket Nos. RM05-25-000 and RM05-17-000 - 115 – 

system events.170 Therefore, the Commission proposes that public utilities, working 

through NERC, modify the ATC-related standards to incorporate a requirement for the 

periodic review and modification of these models (including load flow base cases, short 

circuit data, transient and dynamic stability simulation data, contingency,171 subsystem 

and monitoring files, and production cost models), in order to ensure that they are up to 

date. 

166. Modeling assumptions are a crucial element in the calculation of ATC. The 

Commission proposes that public utilities, working through NERC, develop consistent 

assumptions for use in ATC determinations. The Commission proposes that the 

assumptions used in the calculation of ATC be made consistent among transmission 

providers, to the maximum extent practicable. In general, the Commission believes that 

the assumptions used in the determination of ATC should be consistent with those used 

when planning the operation and expansion of the transmission system. This is necessary 

to remedy the potential for undue discrimination between the manner in which a 

transmission provider plans and operates its system to serve native load and the manner 

in which it calculates ATC for service to third parties. Consequently, the models for 

 170 See U.S.-Canada Power System Outage Task Force, Final Report on the 

August 14, 2003 Blackout in the United States and Canada: Causes and 

Recommendations, Recommendation Number 24 (April 2004). See

https://reports.energy.gov/. 

171 Contingency files should contain information on special protection schemes 

and remedial action plans. 
Docket Nos. RM05-25-000 and RM05-17-000 - 116 – 

short- and long-term ATC calculation should be developed using consistent assumptions 

regarding the load level, generation dispatch, transmission and generation facilities 

maintenance schedules, contingency outages and topology as those used in the planning 

for operation and expansion. In addition, the long-term ATC models should rely to the 

maximum extent practicable upon the same assumptions regarding new transmission and 

generation facilities additions and retirements as those used in the planning for 

expansion. 

167. More specifically, the Commission proposes to direct public utilities, working 

through NERC, to establish consistent assumptions that are related to the modeling of: 

(1) representative load levels, (2) generation dispatch, (3) transmission reservations and 

(4) counterflows, in addition to any other modeling assumptions identified by NERC. 

Regarding the assumptions used for load level modeling in the ATC calculation, the 

Commission proposes to require all transmission providers to have a consistent approach 

to modeling of load levels. With respect to the base generation dispatch, we propose that 

public utilities, working through NERC, establish a method for determining which 

generators should be modeled in service, including guidance on how independent 

generation should be considered. With respect to modeling of particular transactions, the 

Commission believes that a consistent approach is needed on how to simulate power 

flows from points of receipt to points of delivery when sources are unknown. 

Accounting for transmission reservations in an ATC/AFC calculation also should be 
Docket Nos. RM05-25-000 and RM05-17-000 - 117 – 

consistent.172 We note that the purpose of more consistent modeling assumptions is to 

eliminate discretion and the potential for undue discrimination. This proposal is not 

intended to change the manner in which native load customers are served. We seek 

comment on whether (and, if so, how) this proposal would affect service to native load 

customers. 

168. The Commission also supports the development of clear standards on how often 

ATC/AFC and its individual components are calculated and updated. The Commission 

proposes that public utilities, working through NERC and NAESB, develop standards 

requiring that the calculation be performed on a consistent time interval among 

transmission providers and in a manner that closely reflects the actual topology of the 

system concerning generation and transmission outages, load forecast, interchange 

schedules, transmission reservations, facility ratings, and other necessary data. The 

Commission also supports uniform updating of ATC values and components by adjacent 

control areas. 

169. The Commission believes 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. Therefore, we 

propose that public utilities, working through NERC, develop consistent protocols that 

 172 Currently, one method models all appropriate reservations in the power flow 

base case model, when another models only those reservations that are expected to be 

scheduled, and accounts for others by decrementing flowgate AFC. 
Docket Nos. RM05-25-000 and RM05-17-000 - 118 – 

would enable and require the exchange of data among transmission providers. We 

propose that the following data, at a minimum, should 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 calculation frequency, and (7) source / sink modeling identification. In addition, 

NERC may identify other data needs through the standards development process. We 

seek 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. 

170. In order to facilitate the process for achieving consistency in ATC calculations we 

have proposed in this NOPR, the Commission directs Staff to hold a technical 

conference. The technical conference will be transcribed to provide the Commission and 

NERC a record of the comments received at the conference. The Commission will 

provide further guidance regarding the date of the technical conference and the topics it 

intends to address at the technical conference in a subsequent notice. 

Transparency 

 Pro forma OATT 

171. Though the Commission’s requirement that a transmission provider describe its 

ATC calculation methodology in its OATT has not changed, that requirement has been 
Docket Nos. RM05-25-000 and RM05-17-000 - 119 – 

interpreted in various ways. Some transmission providers post a detailed explanation of 

how they calculate ATC, while other transmission providers post very general 

descriptions that fail to offer sufficient detail for third parties to understand how ATC has 

been derived. The Commission is concerned that the lack of transparency in some of the 

descriptions provided by transmission providers gives these transmission providers too 

much discretion to change ATC practices without sufficient oversight and review. The 

Commission also is concerned that this lack of transparency could allow transmission 

providers to unduly discriminate against their competitors when allocating transmission 

service. We agree with commenters that greater transparency is needed into how 

transmission providers calculate and allocate ATC. Accordingly, in order to ensure that 

transmission service is provided in a nondiscriminatory manner, we propose to require 

transmission providers to take certain measures to make their ATC calculation process 

more transparent. We believe that these proposed changes will give transmission 

customers access to sufficient information to be able to examine the integrity of the 

process. Moreover, our proposal for greater consistency in the way ATC is calculated 

should aid in transparency because there will be far fewer differences in the way 

individual transmission providers calculate ATC. This will make it less difficult to 

determine whether ATC is being calculated in an unduly discriminatory manner. 

172. Specifically, we propose to require transmission providers to include, at a 

minimum, in Attachment C of their OATT, the following information concerning their 

ATC calculation methodology (including the calculation of AFC, if applicable). First, we 
Docket Nos. RM05-25-000 and RM05-17-000 - 120 – 

propose to require transmission providers to state their specific mathematical algorithm 

used to calculate their firm and non-firm ATC (and AFC, if applicable) for their 

scheduling horizon (same day and real-time), operating horizon (day ahead and preschedule) and their planning horizon (beyond the operating horizon). Second, we 

propose that transmission providers provide a process flow diagram that illustrates the 

various steps through which the ATC/AFC is calculated. 

173. In addition, we propose to require transmission providers to include in 

Attachment C a detailed explanation of how each of the ATC components is calculated 

for both the operating and planning horizons. Thus, for TTC, a transmission provider 

should: (1) explain its definition of TTC; (2) explain its TTC calculation methodology 

(e.g., load flow, short circuit, stability, transfer studies); (3) list the databases used in its 

TTC assessments; and (4) explain the assumptions used in its TTC assessments regarding 

load levels, generation dispatch, and modeling of planned and contingency outages. 

174. For ETC, we propose to require a transmission provider to explain: (1) its 

definition of ETC; (2) the calculation methodology used to determine the transmission 

capacity to be set aside for native load and non-OATT customers; (3) how point-to-point 

service requests are incorporated; (4) how rollover rights are accounted for; and (5) 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). With regard to (5), we seek comment on whether transmission providers 
Docket Nos. RM05-25-000 and RM05-17-000 - 121 – 

currently are keeping track of when firm service reservations are not scheduled and 

should be released as non-firm. 

175. If a transmission provider uses an AFC methodology to calculate ATC, we 

propose to require it to explain: (1) its definition of AFC; (2) its AFC calculation 

methodology (e.g., load flow, short circuit, stability, transfer studies); (3) its process for 

converting AFC into ATC; (4) what databases are used in its AFC assessments; 

(5) the assumptions used in its AFC assessments; and (6) the reliability criteria used for 

contingency outages simulation. 

176. For TRM, we propose to require a transmission provider to explain: (1) its 

definition of TRM; (2) its TRM calculation methodology (e.g., its assumptions on load 

forecast errors, forecast errors in system topology or distribution factors and loop flow 

sources); (3) the databases used in its TRM assessments; (4) the conditions under which 

the transmission provider uses TRM; and (5) the process used to prevent double-counting 

of contingency outages used in its TTC and TRM calculations. We propose to require 

transmission providers that do not reserve TRM to reflect that in Attachment C. We seek 

comment on the above proposal, specifically on what type of showing a transmission 

provider could make with regard to the process used to prevent double-counting. 

177. Furthermore, in the CBM Order, the Commission required transmission providers 

to post a specific and self-contained narrative explanation of their CBM practices, 

including who performs the assessment (transmission or merchant staff), the 

methodology used to perform generation reliability assessments (e.g., probabilistic or 
Docket Nos. RM05-25-000 and RM05-17-000 - 122 – 

deterministic), whether the assessment method reflects a specific regional practice, the 

assumptions used in those assessments and the basis for the selection of paths on which 

CBM is set aside. In addition, the Commission directed transmission providers to post 

their procedures for allowing CBM during emergencies (with an explanation of what 

constitutes an emergency, the entities that are permitted to use CBM during emergencies 

and the procedures which must be followed by the transmission providers’ merchant 

function and other load-serving entities when they need to access CBM). The 

Commission further stated that if a utility’s practice was not to reserve CBM, it should 

reflect that in Attachment C. We propose to require transmission providers to include 

this narrative in Attachment C of their OATTs. 

178. In addition, for CBM, we propose to require a transmission provider to: 

(1) explain its definition of CBM; (2) list the databases used in its CBM calculations; 

and (3) prove that there is no double-counting of contingency outages when performing 

CBM calculations. 

179. Though we are proposing to require transmission providers to provide greater 

clarity in the description of their ATC calculations, it is our expectation that the reforms 

we propose for greater consistency of ATC methods will minimize the burden on 

transmission providers and customers of assessing various ATC calculation 

methodologies. Ultimately, when the ATC standards development process we propose is 

completed, we expect that Attachment C will refer to the NERC standards and will differ 
Docket Nos. RM05-25-000 and RM05-17-000 - 123 – 

by transmission provider only with respect to the limited elements of the ATC calculation 

that may not have been made consistent. 

OASIS 

180. The Commission’s existing regulations require certain ATC-related information to 

be posted on each transmission provider’s OASIS, while other information is required to 

be provided on request. To ensure that relevant information is available on a timely basis 

to all market participants, we propose to amend our regulations to allow potential 

customers greater access to information that will enable them to obtain service on a nondiscriminatory basis from any transmission provider.173 We believe that our proposed 

reforms will not only enhance the amount and accuracy of information available to 

customers, but will also increase the ability of the Commission and others to detect any 

potentially unduly discriminatory behavior in a transmission provider’s calculation and 

allocation of ATC. 

181. Our regulations state that a transmission provider’s174 ATC and TTC calculations 

shall be performed according to consistently applied methodologies referenced in the 

transmission provider’s OATT and shall be based on current industry practices, standards 

 173 See 18 CFR 37.2 (2005). 

174 We note that various provisions of the OASIS regulations use the term 

“Responsible Party,” which means the transmission provider or an agent to whom the 

transmission provider has delegated the responsibility of meeting any of the requirements 

of the regulations. For simplicity, however, we will use the term “transmission provider” 

here. 
Docket Nos. RM05-25-000 and RM05-17-000 - 124 – 

and criteria.175 We propose to revise this provision to include compliance with the 

reliability standards developed by the ERO – i.e., ATC and TTC calculations shall be 

performed according to consistently applied methodologies referenced in the 

transmission provider’s OATT and shall be based on the ERO reliability standards as 

well as current industry practices, standards and criteria. 

182. The regulations further state that, on request, a transmission provider must provide 

all data used to calculate ATC and TTC for any constrained paths.176 Transmission 

providers also are required to make any system planning studies or specific network 

impact studies performed for customers to determine network impacts publicly available 

on request and to post a list of such studies on the OASIS.177 The Commission proposes 

to maintain these requirements. 

183. The Commission’s OASIS regulations require transmission providers to calculate 

and post ATC and TTC for each posted path.178 The regulations define two classes of 

posted paths based on usage: “constrained” and “unconstrained.” A constrained posted 

path is any posted path for which ATC has been less than or equal to 25 percent of TTC 

at any time during the preceding 168 hours or is calculated to be less than, or equal to, 

 175 See 18 CFR 37.6(b)(2)(i) (2005). 

176 See 18 CFR 37.6(b)(2)(ii) (2005). 

177 See 18 CFR 37.6(b)(2)(iii) (2005). 

178 See 18 CFR 37.6 (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 125 – 

25 percent of TTC for any period during the current hour or the next 7 days. An 

unconstrained posted path is any posted path that is not a constrained posted path.179 The 

Commission proposes to amend the regulations relating to the data posted for constrained 

posted paths, but largely to retain the existing posting requirements for unconstrained 

posted paths, as set forth below. 

184. First, in the CBM Order, 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. The Commission proposes to incorporate these CBM posting 

requirements into its regulations. 

185. With respect to paths for which the utility already posts ATC, TTC, and CBM, 

we further propose to require each transmission provider to also post (and update) the 

TRM value for that path. 

186. Our 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. We do not believe that this regulation has 

 179 See 18 CFR 37.6(b)(1)(iii(2005). Our regulations require transmission 

providers to post ATC and TTC for specific time horizons for constrained posted paths 

and unconstrained posted paths. The Commission proposes to maintain the existing time 

horizons. See 18 CFR 37.6(b)(3)(i)-(ii) (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 126 – 

resulted in sufficient information to determine why ATC values changed. To provide a 

transmission customer with useful information to assist with its evaluation of monthly 

and yearly firm transmission service options, we propose to supplement the existing 

regulations by requiring the transmission provider to post a brief, but specific, narrative 

explanation of the reason for the posted change in the monthly and yearly ATC values on 

a constrained path. This narrative would describe, for example: (1) scheduling of 

planned outages and occurrence of forced transmission outages; (2) de-ratings of 

transmission facilities; (3) scheduling of planned generation outages and occurrence of 

forced generation outages; (4) changes in load forecast, (5) changes in new facilities inservice dates, or other events or assumption changes that cause the ATC value to change. 

We seek 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. We seek comment on whether a similar 

narrative also should be required when ATC remains unchanged at a value of zero for 

some specified period of time. 

187. We propose to maintain the requirement in 18 CFR § 37.6(e)(2)(i) that a 

transmission provider must post the reason for a denial of a request for service. We 

propose, however, to amend this provision to require a transmission provider to maintain 

and make available information supporting the reason for the denial for five years. In 

addition, we propose to extend the time period for which transmission providers must 

maintain transmission service information for audit. Our regulations currently require 
Docket Nos. RM05-25-000 and RM05-17-000 - 127 – 

audit data to be retained and made available upon request for download for three years 

from the date when they are first posted.180 We propose to change the period from three 

to five years. 

188. 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). Thus, the 

Commission 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. We propose to incorporate these requirements in the 

Commission’s regulations and to obligate transmission providers to reevaluate the CBM 

set aside at least quarterly. 

189. We also propose 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. As with other transmission 

request information posted on OASIS, the transmission provider should keep designation 

and termination information posted on OASIS for 90 days and should make designation 

and termination information available upon request for five years, consistent with 18 

CFR 37.7(b) (2005). Transmission customers will be able to query requests to designate 

and terminate a network resource under 18 CFR 37.6(a)(6)(2005). We propose to require 

 180 See 18 CFR 37.7(b) (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 128 – 

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 of 

network resources should include the name of the resource, its geographic and electrical 

location, and the amount of capacity from the unit to be designated as a network resource. 

190. Finally, we remind transmission providers that transfer capability associated with 

transmission reservations that are not scheduled in real time must be included in non-firm 

ATC and posted on OASIS.181

CEII

191. Shortly after the attacks on September 11, 2001, the Commission removed from 

public viewing certain documents that were likely to contain detailed specifications of 

critical infrastructure facilities. CEII is information concerning proposed or existing 

critical infrastructure (physical or virtual) that: (1) relates to the production, generation, 

transportation, transmission, or distribution of energy; (2) could be useful to a person in 

planning an attack on critical infrastructure; (3) is exempt from mandatory disclosure 

under the Freedom of Information Act, 5 U.S.C. § 552 (2000); and (4) does not simply 

give the location of the critical infrastructure. Accordingly, access to transmissionrelated information collected by the Commission has been restricted by the 

Commission’s CEII regulations. Thus, for example, information filed in FERC Form 

 181 Our regulations require non-firm ATC and TTC for constrained posted paths to 

be posted in the same manner as firm ATC and TTC, except that monthly and seasonal 

capability need only be posted if requested. See 18 CFR 37.6(b)(3)(i)(B)(2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 129 – 

No. 715 (including base case power flow data and transmission system maps) as well as 

system planning and network impact studies and models are no longer publicly available. 

However, requesters with a particular need (such as transmission customers and 

consultants with legitimate needs) have the opportunity to access information designated 

as CEII from the Commission by submitting a request to the Commission under the 

procedures set forth in our regulations. In Order No. 643,182 the Commission addressed 

situations in which its regulations require public utilities to disclose information directly 

to the public. The Commission ruled that potential CEII disclosed directly from the 

public utility to the public should be evaluated under the same rules addressing the 

disclosure of CEII from the Commission to the public, i.e., if an entity concludes that 

certain of its information is CEII, it must designate it as such and provide other specified 

information about obtaining access to the CEII through the Commission’s process. The 

Commission also held that it did not intend to restrict an entity’s ability to reach 

appropriate arrangements for sharing CEII, and that all persons with a legitimate need for 

CEII should be able to gain access to it with a minimum of difficulty.183 

192. We believe that much of the information we propose to require transmission 

providers to provide in this proposed rulemaking will not pose CEII concerns. If 

 182 Amendments to Conform Regulations with Order No. 630, Order No. 643, 

68 FR 52089 (Sep. 2, 2003), FERC Stats. & Regs. ¶ 31,149 (2003). 

183 Id. at P 16. 
Docket Nos. RM05-25-000 and RM05-17-000 - 130 – 

commenters believe that any of the information is CEII, they should explain the basis for 

that view. We recognize that requiring interested persons to use the existing CEII 

process to access information we propose to require transmission providers to provide in 

this rulemaking could undermine our goal of providing increased transparency to 

information necessary to evaluate the use of the transmission system. As a result, we 

seek 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 persons. 

Additional Data Posting 

193. Notwithstanding our proposed reforms requiring greater consistency of and 

increased transparency into ATC calculation methodologies, certain aspects of ATC 

calculation may remain committed to the discretion of the transmission provider. Thus, 

we believe that additional reporting requirements may be necessary to detect undue 

discrimination. Accordingly, we propose to add a requirement in our regulations for 

transmission providers to post on OASIS certain metrics related to the provision of 

transmission service under the pro forma OATT. Specifically, we propose to require 

transmission providers to post data each month concerning transmission service requests 

associated with particular paths or flowgates that would clearly identify the number of 

requests that have been accepted and the number of requests that have been denied during 

the prior month. The posted data would show: (1) the number of non-affiliate requests 

for transmission service that have been rejected and (2) the total number of non-affiliate 
Docket Nos. RM05-25-000 and RM05-17-000 - 131 – 

requests for transmission service that have been made. This posting would 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). We also propose that the transmission provider post similar 

information for affiliate transactions. In other words, the transmission provider would 

also post: (1) the number of affiliate requests for transmission service that have been 

rejected, and (2) the total number of affiliate requests for transmission service that have 

been made. Similarly, this posting would 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). 

194. Another area of discretion is the load forecasts used by the transmission provider 

when computing ATC. The Commission recognizes that the lack of transparency 

regarding transmission providers’ forecasted and actual use of the transmission system 

makes it difficult to determine whether an appropriate amount of capacity is being set 

aside for service to native load. To address this concern, we are considering additional 

posting requirements. For example, should transmission providers make available their 

underlying load forecast assumptions for all ATC calculations? In addition, should 

transmission providers post, on a daily basis, their actual daily peak load for the prior 

day? We believe that this posting of forecasted and actual loads would allow the 

Commission and others to make a meaningful comparison of these elements. We invite 

comment on whether this information would be helpful for such a comparison. We also 
Docket Nos. RM05-25-000 and RM05-17-000 - 132 – 

seek comment on the overall benefits of posting metrics and on potential alternative 

metrics. 

195. For all of our proposed OASIS reforms, we propose to require public utilities, 

working through NAESB, to develop standards for consistent methods of posting the new 

requirements on OASIS so that a common format is used. 

B. Transmission Planning – Coordinated, Open and Transparent 

Planning

196. Order No. 888 set forth certain minimum requirements for transmission system 

planning. For example, the pro forma OATT requires transmission providers to plan for 

the transmission needs of their network customers on a comparable basis (section 28.2), 

and it requires them to expand their systems to accommodate firm point-to-point 

customer requests (sections 13.5 and 15.4) that cannot be satisfied due to transmission 

constraints or satisfied more economically via redispatch. In addition, 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.184 However, the 

Commission did not require joint planning between transmission providers and their 

 184 See Order No. 888-A at 30,311. 
Docket Nos. RM05-25-000 and RM05-17-000 - 133 – 

customers or between transmission providers in a given region,185 nor did it impose any 

specific requirements regarding the manner in which transmission providers should 

coordinate their transmission system planning with their pro forma OATT customers. 

The only section of the pro forma OATT that directly speaks to joint planning is section 

30.9, which provides that for facilities constructed by a network customer, the network 

customer must receive credit where such facilities are jointly planned and installed in 

coordination with the transmission provider.186 

197. In the NOI, the Commission asked several questions about joint planning between 

transmission providers and their customers. For example, we asked whether joint 

planning should be made mandatory, particularly when transmission requests affect 

adjacent transmission systems. We also inquired whether joint planning should be 

subject to an annual reporting requirement or audits. Additionally, we asked for 

comment on a number of issues designed to determine whether any pro forma OATT 

reforms are necessary to ensure that the transmission system is expanded so that 

customers have adequate transmission service. As the comments below indicate, 

commenters generally all believe that joint and regional planning are necessary and 

 185 See id.

186 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. 
Docket Nos. RM05-25-000 and RM05-17-000 - 134 – 

desirable, but there is a split over whether it should continue to be voluntary or should be 

made a requirement. 

Comments Supportive of Mandatory Joint and Regional Planning

198. A number of commenters contend that joint planning between transmission 

providers and their customers should be required by the pro forma OATT. Most of these 

commenters also advocate joint planning among transmission providers in a given region. 

In perhaps the strongest comments on the topic, TDU Systems and TAPS request that the 

Commission mandate an open, regional transmission expansion planning process that 

provides opportunities for transmission customers to join and participate in the planning 

process. Many other commenters also support joint and regional planning in some form 

or another, with some focusing particularly on requiring such planning when adjacent 

transmission systems are affected.187 Bonneville and Williams also assert that there is 

already Commission precedent for joint planning in our procedures on large generator 

interconnections, which require the coordination of studies when interconnection requests 

affect other systems. EPSA states that the Commission should require that neighboring 

systems formalize the process under which broad regional models are developed and used 

to study requests on any system within a broadly defined region. Powerex points out that 

 187 E.g., AEP, Alcoa, APPA, Bonneville, Calpine, EPSA, Lafayette, National Grid, 

NCPA, NRECA, Old Dominion, Trans-Elect, Williams, and Xcel. Though it does not 

generally support mandatory joint and regional planning, EEI recommends that the 

Commission modify the pro forma OATT to address planning when transmission 

requests require upgrades on or otherwise adversely affect adjacent transmission systems.
Docket Nos. RM05-25-000 and RM05-17-000 - 135 – 

the lack of regional transmission planning is one of the most difficult issues faced in the 

Pacific Northwest, and PPL asserts that transmission planning and expansion in the 

Western Interconnection does not support a competitive market. 

199. In addition, many commenters contend that transmission providers should be 

required to report on an annual basis the joint and regional planning that has occurred or 

been requested.188 TAPS states that an annual filing noticed by the Commission that 

gives the public an opportunity to comment should be buttressed with audits, in order to 

ensure that transmission providers are taking joint planning with their network customers 

(and neighboring systems) seriously. EPSA likewise contends that transmission 

providers should be required to report to the Commission on an annual basis the joint 

planning that has occurred or been requested on their systems, and that the Commission 

should conduct audits to determine the level of compliance with any joint planning 

requirement or agreement. 

200. The commenters that advocate mandatory joint and regional planning assert that it 

is needed because transmission providers unduly discriminate against their customers 

when planning their transmission systems. For example, a number of commenters assert 

that transmission providers meet their own needs for transmission planning and 

construction before (and often without) meeting those of their customers.189 NRECA 

 188 E.g., East Texas Cooperatives, EPSA, FMPA, MidAmerican, and TAPS. 

189 E.g., FMPA, Midwest Municipals, NCPA, and NRECA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 136 – 

asserts that since the implementation of Order No. 888, a number of public utility 

transmission providers – despite clearly stated obligations in the pro forma OATT – have 

not planned for their load-serving transmission customers on a basis comparable to that 

of their own bundled retail native load. TDU Systems believe that joint and regional 

transmission planning is a critical component of ensuring comparability between a 

transmission provider’s use of the transmission system and a network customer’s use of 

the transmission system, largely because transmission providers have an incentive to 

thwart the expansion planning process. Both NRECA and TDU Systems argue that the 

planning processes in RTOs and ISOs also are insufficient because they often only allow 

customer input after transmission plans are developed by individual transmission 

providers. 

201. TAPS asserts that the absence of joint planning has resulted in unduly 

discriminatory transmission service. For comparable service to be a reality, TAPS asserts 

that the transmission system must be planned and built for customer needs, just as it must 

be planned and built to meet the transmission providers’ need to provide service to their 

native loads. Old Dominion contends that transmission providers often locate 

transmission in such a way that it favors their own generation. According to Lafayette, 

transmission providers have increased their generation dominance by inadequately 

planning for the needs of their transmission customers so that they are unable to turn to 

alternative suppliers. East Texas Cooperatives also argues that some transmission 

providers continue to plan their systems in isolation from the needs of other load-serving 
Docket Nos. RM05-25-000 and RM05-17-000 - 137 – 

entities. EPSA concludes that the transmission needs of non-transmission provider 

customers are simply not integrated effectively into the planning process. APPA notes 

that the original goal of the pro forma OATT -- an inclusive planning process that takes 

into account on a comparable basis the load growth and new generation resource needs of 

all loads served using the transmission provider’s system -- has not been achieved. Many 

commenters assert that joint and regional transmission planning is necessary in order to 

ensure adequate infrastructure development.190 Others focus on the need for joint and 

regional planning to address the fact that changes on one system often affect transmission 

service on adjacent systems.191 Lastly, APPA blames substantial and rising congestion 

costs on inadequate transmission planning, and EPSA contends that better transmission 

planning is needed to support a competitive electricity market. 

Comments Supportive of Voluntary Joint and Regional Planning

202. Another large group of commenters, including many investor-owned utilities, 

stress that joint and regional planning, while laudable, should not be mandatory and that 

it should continue to be voluntary or that processes are already in place to encourage 

 190 E.g., AEP, Calpine, Constellation, East Texas Cooperatives, ELCON, NRECA, 

and TransAlta. 

191 E.g., Alcoa and EPSA. EEI acknowledges the planning difficulties that arise 

when a transmission request on one system causes the need for upgrades to another 

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

regional planning.192 Progress Energy, for example, contends that there are several 

formalized processes in place today that foster joint and regional planning, such as the 

process in North Carolina. Southern points out that in addition to participating in 

Southeastern Electric Reliability Council (SERC) planning activities, it is engaged in 

other types of joint regional planning (e.g., through the Georgia Integrated Transmission 

System (Georgia ITS)).193 Nevada Companies supports the approach already used in the 

WECC, which employs interconnection-wide models for planning. Nevada Companies 

explains that these studies are then made available to all other WECC transmission 

providers. In addition, APS, Tacoma, and WAPA point to numerous forums (e.g., the 

Southwest Area Transmission planning group and the Southwest Transmission 

Expansion Plan process) where transmission providers and other industry stakeholders 

coordinate their transmission plans. LPPC also states that the Georgia ITS has provided 

benefits to participants and the region – in the form of improved investment in 

infrastructure and through the introduction of new sources of capital. Lastly, some 

 192 E.g., Cinergy, Entergy, KCP&L, LPPC, MidAmerican, Nevada Companies, 

North Carolina Commission, Northwestern, PNM-TNMP, Progress Energy, Salt River, 

Snohomish, South Carolina Regulatory Staff, Southern, Tacoma, and WAPA. 

Nevertheless, KCP&L, Nevada Companies, and Progress Energy join with EPSA in 

calling for a more formalized process for addressing base case and expansion plans. 

193 Georgia ITS consists of jointly-owned transmission facilities, which are owned 

by the Southern subsidiary Georgia Power, the Municipal Electric Authority of Georgia, 

the Georgia Transmission Corporation – a cooperative utility – and Dalton Utilities – a 

municipal system. 
Docket Nos. RM05-25-000 and RM05-17-000 - 139 – 

commenters point out that collaborative regional planning already occurs in RTO and 

ISO regions.194 With regard to PJM, however, TDU Systems argues that better 

transmission planning is required due to PJM’s “rubber-stamping” of transmission 

provider identified transmission upgrades. Exelon states that the Northeastern ISO/RTO 

Planning Coordination Protocol is a formal agreement, executed in 2004, among the 

PJM Interconnection, the New York Independent System Operator, and ISO New 

England, pursuant to which the three organizations conduct a comprehensive process of 

coordinating system planning activities. 

203. With regard to the imposition of reporting requirements, many commenters argue 

that transmission providers already are required to report joint planning activities.195 

EEI, for example, contends that joint planning activities under section 30.9 of the pro 

forma OATT currently are required to be reported on each transmission provider’s 

OASIS. EEI argues that audits should not be required. Bonneville contends that, at least 

in the Pacific Northwest, annual reporting and audits are not needed. Bonneville states 

that transmission planning staffs already bear a heavy workload; for example, 

Bonneville’s planning staff must address many requests for transmission and 

interconnection service, as well as conduct regional planning efforts and comply with 

regional and national reliability initiatives. Northwestern states that reporting 

 194 E.g., Ameren, CAISO, Exelon, ISO New England, and MidAmerican. 

195 E.g., Bonneville, EEI, KCP&L, PNM-TNMP, Salt River, Tacoma, and WAPA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 140 – 

requirements or audits are not needed and would be burdensome to the transmission 

provider, distracting it from performing its joint planning responsibilities. 

Current pro forma OATT Planning Responsibilities

204. Order No. 888 and the pro forma OATT require that transmission providers plan 

and upgrade their transmission systems to provide comparable open access transmission 

service for their transmission customers. For example, 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.” 

205. 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 141 – 

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 pointto-point transaction because of insufficient capability on its system, it will “use due 

diligence to expand or modify its Transmission System to provide the requested Firm 

Transmission Service.” Section 15.4 goes on to provide that “the Transmission Provider 

will conform to Good Utility Practice in determining the need for new facilities and in the 

design and construction of such facilities.” Importantly, however, 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”). Order No. 888 does 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.196 

 196 Certain transmission data is required to be provided annually in the FERC 

Form 715 (e.g., Part 2 – Power Flow Base Cases, Part 3 – Transmitting Utility Maps and 

Diagrams, Part 4 – Transmission Planning Reliability Criteria, Part 5 – Transmission 

Planning Assessment Practices, and Part 6 – Evaluation of Transmission System 

Performance). As discussed below, we do not believe that the FERC Form 715 reporting 

requirements have satisfied the need for transparency with regard to transmission 

planning.
Docket Nos. RM05-25-000 and RM05-17-000 - 142 – 

The Need for Reform

206. As discussed more fully in Part III.C above, in the ten years since Order No. 888 

was issued, the Nation has witnessed a decline in transmission investment relative to load 

growth. As a result, transmission capacity per MW of peak demand has declined in every 

NERC region, and it has been estimated that capital spending must increase significantly 

to ensure system reliability and to accommodate wholesale electric markets. Many have 

argued that inadequate expansion of the transmission grid has contributed to the 

widespread transmission constraints that plague most regions of the country, as reflected 

in the limited amounts of ATC posted in many regions, increased frequency of denied 

transmission services requests, and increasingly common transmission service 

interruptions or curtailments, all of which make it more difficult for transmission 

customers to transfer power. In short, it has become clear that since Order No. 888 was 

issued, the Nation’s transmission grid has not been planned and developed adequately 

and projections suggest that without reform this trend will continue. 

207. The need for transmission planning reform also has been 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 143 – 

in early 2004,197 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).198 

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, as well as critical infrastructure to support national security and environmental 

concerns.199 

208. Transmission providers 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. As the Commission noted in Order No. 888, “[i]t is in 

the economic self-interest of transmission monopolists, particularly those with high-cost 

 197 The CECA Transmission Infrastructure Forum included representatives from 

such diverse constituencies as investor-owned utilities, rural electric cooperatives, 

municipal power systems, federal power systems, independent power producers, 

equipment manufacturers, the U.S. Congress, the Commission, the U.S. Department of 

Energy, state legislatures, state public utility commissions, state energy offices and 

consumer advocates, consumer and environmental organizations, independent 

consultants, and academic institutions. 

198 Available at http://www.cecarf.org/Publications/PublicationsAllDate.html.

199 See, e.g., CECA Report at 10-11. 
Docket Nos. RM05-25-000 and RM05-17-000 - 144 – 

generation assets, to deny transmission or to offer transmission on a basis that is inferior 

to that which they provide themselves.”200 This statement continues to be true today. In 

upholding the Commission’s authority to require open access in Order No. 888, the court 

in TAPS v. FERC noted that “[u]tilities that own or control transmission facilities 

naturally wish to maximize profit. The transmission-owning utilities thus can be 

expected to act in their own interest to maintain their monopoly and to use that position to 

retain or expand the market share for their own generated electricity, even if they do so at 

the expense of lower-cost generation companies and consumers.”201 Thus, even when 

transmission providers do address congestion, they have an incentive to do so in a 

manner that benefits their own generation or loads rather than the generation or loads of 

their competitors. These disincentives frustrate new investment that could remedy both 

“local” congestion (i.e., within the transmission provider’s control area) and congestion 

between control areas, as well as remedy undue discrimination and increase bulk power 

trade. 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 

 200 Order No. 888 at 31,682. 

201 225 F.3d at 684; see also New York v. FERC, 535 U.S. at 8-9 (addressing 

Order No. 888’s open access requirements, the Court noted 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.”) (citation and footnote omitted). 
Docket Nos. RM05-25-000 and RM05-17-000 - 145 – 

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. 

209. The existing pro forma OATT does not adequately address the above-referenced 

problems. As noted, there is no general requirement that a transmission provider 

coordinate its transmission planning with customers, market participants, or its 

interconnected neighbors.202 Additionally, though the pro forma OATT does require 

transmission providers to plan for the needs of their network customers and to expand 

their systems to provide service to point-to-point customers, there is no requirement that 

the overall transmission planning process be open to customers, competitors, and state 

commissions. Rather, the transmission provider currently is allowed to create its own 

transmission plan with limited or no input from affected market participants or other 

affected entities, such as state commissions. There is also no requirement that the 

planning process be transparent. While we recognize that certain planning information is 

required to be filed annually in FERC Form No. 714 – Annual Electric Control and 

Planning Area Report and FERC Form 715 – Annual Transmission Planning and 

 202 As discussed more fully in Part V.C.2, section 30.9 of the current pro forma

OATT may inhibit coordinated planning by making transmission providers reluctant to 

engage in coordinated planning, because of the requirement to give customers credits for 

jointly planned facilities. We are proposing to sever the link between credits and 

planning, and treat the two issues separately within the pro forma OATT. 
Docket Nos. RM05-25-000 and RM05-17-000 - 146 – 

Evaluation Report, this does not appear to provide sufficient transparency to remedy the 

remaining concerns expressed in this proceeding about the potential for undue 

discrimination in planning. 

210. 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 input into whether a 

particular plan treats all loads and generators comparably. Without sufficient 

transparency, market participants have no means to determine whether the plan 

developed by the transmission provider in isolation is discriminatory. Moreover, the 

process is inefficient. Disputes over discrimination occur primarily after-the-fact because 

there is insufficient coordination and transparency between transmission providers and 

their customers for purposes of planning. The Commission has a duty to prevent undue 

discrimination in the rates, terms, and conditions of public utility transmission service, 

and therefore, an obligation to remedy these transmission planning deficiencies. The 

Commission’s authority to remedy undue discrimination is broad.203 In addition, new 

section 217 of the FPA requires the Commission to use its FPA authorities in a manner 

that facilitates the planning and expansion of transmission facilities to meet the 

reasonable needs of load-serving entities. Finally, we note that a more transparent and 

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

for undue discrimination (citing Associated Gas Distributors v. FERC, 824 F.2d 981, 998 

(D.C. Cir. 1987)). 
Docket Nos. RM05-25-000 and RM05-17-000 - 147 – 

coordinated regional planning process can support the DOE's responsibilities under 

EPAct 2005 section 1221 to study transmission congestion and issue reports designating 

National Interest Transmission Corridors. 

211. We are encouraged that since the adoption of open access in Order No. 888, a 

number of voluntary coordinated and regional planning efforts have been developed 

throughout the country, including those administered by RTOs and ISOs. 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. The Commission also notes that there are several 

other promising efforts to establish voluntary coordinated and regional planning efforts 

around the country. For example, WECC is in the process of expanding its reliability 

responsibilities to include comprehensive transmission planning to address the regional 

economic transmission needs of its members and other stakeholders in its regional 

footprint. In addition, each of the subregions in WECC has a coordinated transmission 

planning process that, in varying degrees, is open to market participants and, in some 

instances, has resulted in significant new transmission being built on a joint ownership 

basis. In North Carolina, Duke, Progress Energy, and two other organizations – North 

Carolina Electric Membership Corporation and ElectriCities of North Carolina, Inc. – 

have endeavored to create and implement a collaborative electric transmission planning 

process in that state. This process provides for broad stakeholder input as well an 
Docket Nos. RM05-25-000 and RM05-17-000 - 148 – 

independent facilitator. Other models for coordinated planning include the Georgia ITS 

and joint ownership arrangements like it around the country. 

212. We fully support these voluntary efforts and believe they are consistent in 

significant respects with the nature of the reforms we are proposing for transmission 

planning under the pro forma OATT. In those regions and subregions that already have 

adopted significant reforms, our proposal may require only modest changes, while other 

regions and subregions may need to undertake more significant changes to the way in 

which the transmission system is planned today. 

213. Today, numerous competing interests have a need to utilize the transmission grid, 

and yet in many areas of the country that grid is planned much the same way as it was 

before the electric industry matured into a regional business and Order No. 888 was 

implemented. That is, the same public utilities that own and control the grid also control 

the planning process that governs when and how the grid is expanded and upgraded. In 

short, the transmission grid is being utilized in a fundamentally different way, consistent 

with the intent of open access, and a decade of experience has shown us that in order to 

remedy undue discrimination, the existing provisions of the pro forma OATT respecting 

transmission system planning must be reformed. Accordingly, in order to provide for 

more comparable open access transmission service, eliminate the potential for undue 

discrimination and anticompetitive conduct, and satisfy our statutory responsibilities 

under section 217 of the FPA, we propose that each public utility transmission provider 

participate in an open and transparent local and regional planning process that addresses 
Docket Nos. RM05-25-000 and RM05-17-000 - 149 – 

certain fundamental principles of transmission planning. As we indicated above, existing 

regional planning processes will be expected to meet or exceed the transmission planning 

principles we outline in this proposed rule. 

Coordinated, Open, and Transparent Transmission Planning

214. In order to eliminate the potential for undue discrimination as described above, 

and to ensure that comparable transmission service is provided by all public utility 

transmission providers, including RTOs and ISOs, we propose to amend the pro forma

OATT to require coordinated, open, and transparent transmission planning on both a 

local and regional level. We propose to require each public utility transmission provider 

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 coordinated and regional 

planning principles.204 In the alternative, transmission providers may make a compliance 

filing in this proceeding describing their existing coordinated and regional planning 

process and showing that it is consistent with or superior to the requirements set forth 

below. Moreover, we expect municipal, cooperative, and other public power entities to 

participate in these processes as well, consistent with their obligation to provide 

reciprocal transmission service as detailed in Order No. 888. An open and transparent 

regional planning process cannot succeed unless all transmission owners participate. 

 204 The revised pro forma OATT reflects the proposed planning requirement in 

sections 15.4, 16.1, 17.2(x), 28.2, 29.2, 31.6, and Attachment K. 
Docket Nos. RM05-25-000 and RM05-17-000 - 150 – 

Under our proposal in this NOPR, a coordinated, open and transparent process must 

satisfy the following eight principles: 

1. Coordination – The transmission provider must meet with all its 

transmission customers and interconnected neighbors to develop a 

transmission plan on a nondiscriminatory basis. The Commission seeks 

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. 

2. Openness – Transmission planning meetings must be open to all affected 

parties (including all transmission and interconnection customers, and state 

commissions). The Commission seeks comment on whether there are any 

circumstances under which participation should be limited, e.g., to address 

confidentiality concerns. 

3. Transparency – The transmission provider is required to disclose to all 

customers and other stakeholders the basic criteria, assumptions, and data 

that underlie its transmission system plans. The Commission seeks 

comment on whether the information provided in FERC Form 715 is 

adequate and, if not, what additional detail should be provided. The 

Commission also seeks comment on the format for disclosure, including 

protections to address confidentiality concerns. 
Docket Nos. RM05-25-000 and RM05-17-000 - 151 – 

4. Information Exchange – Network transmission customers are 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; and point-to-point customers are required 

to submit any projections they have of a need for service over the planning 

horizon and at what receipt and delivery points. The Commission seeks 

comment on whether specific requirements should be adopted for this 

information exchange.205 The transmission provider must allow market 

participants the opportunity to review and comment on draft transmission 

plans. 

5. Comparability – After considering the data and comments supplied by 

market participants, the transmission provider is 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. 

 205 For network service, some of this information already is required by 

sections 29, 30 and 31 of the pro forma OATT, but to the extent it is not, we propose to 

require customers to provide additional information as necessary for the transmission 

provider to develop a system plan. 
Docket Nos. RM05-25-000 and RM05-17-000 - 152 – 

6. Dispute Resolution – The transmission provider must 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’s 

Dispute Resolution Service is available to assist transmission providers in 

developing a dispute resolution process. In addition to informal dispute 

resolution, affected parties would have the right to file complaints with the 

Commission under FPA section 206. The Commission seeks comment on 

whether any specific dispute resolution processes should be required. 

7. Regional Participation – In addition to preparing a system plan for its own 

control area on an open and nondiscriminatory basis, the transmission 

provider is 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 strongly encourages that such 

coordination 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 recognizes 

that, as in the West, it may be appropriate to organize regional planning 

efforts on both a subregional and regional level. The Commission seeks 

comment on whether there are existing institutions (such as the NERC 
Docket Nos. RM05-25-000 and RM05-17-000 - 153 – 

regional councils or subregional planning groups) that are well situated to 

perform or coordinate this function. 

8. Congestion Studies – The transmission provider is required annually to 

prepare studies identifying “significant and recurring” congestion and post 

such studies on its OASIS. The studies should analyze and report on the 

location and magnitude of the congestion; possible remedies for the 

elimination of the congestion, in whole or in part; the associated costs of 

congestion; and the cost associated with relieving congestion through 

system enhancements (or other means). The Commission seeks 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 required 

congestion studies would address both “local” congestion (i.e., within the 

transmission provider’s system) and congestion between control areas and 

subregions. The purpose of this requirement is to ensure that affected 

market participants, state commissions, and this Commission understand 

both the costs of recurring transmission congestion and the remedies. The 

Commission seeks comment on how this information should be used by the 

transmission provider and market participants to address significant and 

recurring congestion. 
Docket Nos. RM05-25-000 and RM05-17-000 - 154 – 

215. The Commission encourages the use of an independent third party to oversee or 

coordinate the planning process. The Commission is not proposing to require an 

independent third party to control the process, but does believe that independence can 

provide greater confidence in the planning process and resulting studies. Independence 

can take many forms, from having an independent entity resolve disputes over planning 

assumptions and decisions (as in an RTO) to having an independent consultant coordinate 

and otherwise perform the annual congestion studies referred to above. The Commission 

seeks comment on the levels of independence that can provide benefits and the 

institutions that could offer such independence, such as whether Regional Entities under 

the ERO could provide such independence. 

216. Additionally, the Commission strongly encourages the participation of state 

commissions and other state agencies, particularly with regard to regional planning, in the 

coordinated transmission planning processes being proposed in this NOPR. The 

participation and support of state commissions and other state agencies is important 

because state commissions regulate the cost of transmission that is included in bundled 

retail rates and states also perform transmission siting. Many states also have 

traditionally been involved in utility planning in some way for their state or region. The 

Commission seeks comment on how best to accommodate effective state participation. 

217. The Commission seeks comment on several aspects of this proposal. First, the 

Commission seeks comment on how much flexibility each transmission provider in a 

region should be given in implementing any principles adopted. Second, the Commission 
Docket Nos. RM05-25-000 and RM05-17-000 - 155 – 

seeks comment, by way of examples, on transmission planning processes that comply 

with the proposed transmission planning reforms in principle. 

218. Third, we seek 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. For example: 

a. We seek comment on whether there should be a principle or guideline to 

govern the recovery and allocation of costs associated with funding the 

regional planning requirement. To devote the resources necessary to 

support an open and transparent regional planning process, we recognize 

that the participating entities must be assured of recovery of their costs, as 

well as assured that the costs will be borne equitably by all parties 

benefiting from the process. 

b. We seek comment on whether there should be a requirement that, at least 

for large new transmission projects (such as new regional backbone 

facilities), there be an open season to allow market participants to 

participate in joint ownership of these projects. We believe that such a 

requirement could stimulate more investment in the grid and ensure that all 

customers have the ability to participate in new projects on a 

nondiscriminatory basis, including smaller market participants that cannot 
Docket Nos. RM05-25-000 and RM05-17-000 - 156 – 

support the construction of large new facilities on their own.206 We seek 

comment on whether to include such a requirement and, if so, what 

conditions or limitations should be associated with it. 

c. We further seek 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 process 

would allow interested entities, including state resource agencies, siting 

bodies and commissions, load-serving entities, or other market participants 

to request that the transmission provider model grid upgrades needed to 

accommodate the construction of new resources, e.g., remote coal, nuclear 

or wind on a local and regional basis and prior to the existence of an actual 

proposal for such resources. Such a process could provide the information 

necessary to allow interested entities to proactively evaluate, on a 

nondiscriminatory basis, different resource options in light of the differing 

 206 We note that transmission providers in the Western Interconnection already 

participate in regional and sub-regional transmission planning processes that include the 

opportunity for joint financing and ownership of transmission facilities. Such facilities 

are typically owned by the participants as “tenants in common” with each participant 

owning a pro rata share of the land and common facilities and sharing the costs and 

expenses in proportion to their ownership percentage in each project. Additionally, all 

owners participate in the oversight and administration of jointly-owned projects through 

representation on various administration committees. Among other benefits, this has 

allowed all participating utilities, large and small, to take advantage of the economies of 

scale associated with larger transmission projects. 
Docket Nos. RM05-25-000 and RM05-17-000 - 157 – 

transmission infrastructure needs associated with them. We recognize that 

resource planning is traditionally performed at the state level and do not 

believe that any such study process would conflict with these state 

prerogatives. To the contrary, we believe such a study process could 

provide states better information to evaluate all relevant resource options in 

exercising their resource adequacy authority. 

d. We also seek comment on whether we should require public utilities to 

develop cost allocation principles to address the sharing of the costs of new 

transmission projects. Would the development of specific cost allocation 

principles provide greater certainty and hence support the construction of 

new infrastructure? Or is cost allocation better handled on a case-by-case 

basis? We also seek comment on how, as part of any cost allocation 

process, to address the fact that upgrades that may not be needed for 

reliability in the near term (e.g., 3-5 years) may be necessary to support 

reliability in the longer term (e.g., 10-15 years). Furthermore, because 

transmission upgrades, particularly multi-state regional backbone facilities, 

often can require 10 to 15 years to construct, we seek comment on whether 

the planning process proposed here 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. 
Docket Nos. RM05-25-000 and RM05-17-000 - 158 – 

219. Finally, the Commission seeks comment on the level of detail to be required in 

transmission providers’ OATTs. 

C. Transmission Pricing 

220. Order No. 888 and the pro forma OATT included primarily non-rate terms and 

conditions of open access non-discriminatory transmission service. The Commission 

required transmission providers to propose corresponding rates in a subsequent filing 

under FPA section 205. Similarly, here we do not propose to undertake a comprehensive 

overhaul of our transmission pricing policies. We do, however, propose a number of 

reforms to several discrete provisions in the pro forma OATT, as further described below. 

We also provide a clarification of our policy for pricing of system expansions. 

1. Imbalances 

Energy Imbalances 

221. In Order No. 888, the Commission concluded that six ancillary services must be 

included in an OATT.207 One of those ancillary services is energy imbalance service 

under Schedule 4 of the pro forma OATT.208 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 

 207 Order No. 888 at 31,703. 

208 Id.
Docket Nos. RM05-25-000 and RM05-17-000 - 159 – 

control area.209 The Commission recognized 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.210 

222. The Commission found that the 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.211 The deviation band established 

by the Commission is 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.212

223. 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).213 In addition, the Commission 

 209 See id. at 31,960. 

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

211 Id.

212 Id. at 30,232. 

213 Id. at 30,229. 
Docket Nos. RM05-25-000 and RM05-17-000 - 160 – 

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.214 With respect to the price of energy 

imbalance service, the Commission explained that it intentionally did not provide detailed 

pricing requirements.215 Instead, the Commission required transmission providers to 

propose rates for energy imbalance service.216

224. 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 

 214 Id. The Commission further stated that the pro forma OATT permits schedule 

changes up to twenty minutes before the hour at no charge, and that it would allow the 

transmission provider and the customer to negotiate and file another deviation band more 

flexible to the customer, if the same deviation band is made available on a not unduly 

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

215 Id. at 30,234. 

216 Id.
Docket Nos. RM05-25-000 and RM05-17-000 - 161 – 

cost for the hour the deviation occurred.217 Outside the deviation band, transmission 

providers either charge the transmission customer: (1) a percentage of the utility’s 

system cost, such as 110 percent of incremental costs for underscheduling or 90 percent 

of decremental costs for overscheduling, or (2) the greater of a percentage of system costs 

or a fixed charge, such as $100 per MWh.218 

Generator Imbalances

225. While the Commission found in Order No. 888 that energy imbalance was an 

ancillary service, it also recognized that differences arise between energy scheduled for 

delivery from a generator and the amount of energy actually generated in an hour,219

commonly called generator imbalance. It concluded, however, that a generator should be 

able to deliver its scheduled hourly energy with precision and expressed concern that if it 

were to allow the generator to deviate from its schedule by 1.5 percent without penalty, 

so long as it returned the energy in kind at another time, it would discourage good 

 217 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). 

218 See Arizona Electric.; see also Idaho Power Co., 102 FERC ¶ 61,351 (2003); 

see also 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). 

219 Order No. 888-A at 30,230. 
Docket Nos. RM05-25-000 and RM05-17-000 - 162 – 

generator operating practices.220 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.221 

226. Subsequently, however, the Commission, in a number of cases, accepted 

modifications to a transmission provider’s OATT to include generator imbalance 

provisions.222 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.223 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 

 220 Id.

221 Id. 

222 See, e.g., Niagara Mohawk Power Corp., 86 FERC ¶ 61,009 (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). 

223 Order No. 2003-B at P 74-75. 
Docket Nos. RM05-25-000 and RM05-17-000 - 163 – 

imbalance provision of the pro forma OATT.224 In particular, the Commission proposed 

that generator imbalance provisions for intermittent resources would reflect a deviation 

band of +/- 10 percent (with a minimum of 2 MW) and allow net hourly intermittent 

generator imbalances within the deviation band to be settled at the system incremental 

cost at the time of the imbalance.225 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. 

227. 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.226 Generator imbalance rates for 

 224 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). 

225 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 Energy Co., 87 FERC ¶ 61,170 

at 61,179 (1999). 

226 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. RM05-25-000 and RM05-17-000 - 164 – 

overdeliveries range from 90 percent227 of system decremental cost to 50 percent228 of the 

decremental cost. 

228. In the NOI, we asked several questions about the need to modify the treatment of 

energy and generator imbalances. For example, with respect to energy imbalances, the 

Commission asked whether the deviation band of +/-1.5 percent continues to be 

appropriate and whether penalty charges should be eliminated entirely for transmission 

customers, or whether transmission customers should be charged no more than the 

control area’s cost of supplying energy to correct the imbalance. With respect to 

generator imbalances, the Commission asked if comparability in the treatment of 

generator imbalances is needed, how generator imbalances should be priced, and whether 

a generator imbalance provision should be included as a schedule in the pro forma OATT 

rather than in generator interconnection agreements.229

Comments

229. Many commenters assert that the deviation band of 1.5 percent for energy 

imbalances continues to be appropriate. EEI argues that the deviation band for energy 

imbalance service is reasonable because it appropriately balances the need to protect 

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

generator imbalance agreements). 

228 See Duke Delegated Letter Order. 

229 NOI at P 31. 
Docket Nos. RM05-25-000 and RM05-17-000 - 165 – 

transmission system reliability and the need for operational flexibility. LG&E argues that 

the deviation band of +/- 1.5 percent and associated penalties for transactions that fall 

outside this band are an appropriate means of disciplining market participants. Southern 

argues that allowing a larger deviation band could encourage gaming and leaning on the 

system, which ultimately would jeopardize reliability. Southern adds that allowing 

deviations of more than 1.5 percent without penalty could cause, among other things, 

inefficient use of generation resources and inappropriate cost shifting from those most 

able to control imbalances to those lacking such control. 

230. Several commenters assert that the deviation band for energy imbalances should 

be modified. APPA argues that imbalances outside the deviation band currently must be 

paid off at rates that often bear no resemblance to the actual cost that the transmission 

provider likely incurs to deal with the imbalance. APPA recommends revising Schedule 

4 to increase the deviation band and to institute a graduated series of increasing penalties 

outside of the expanded deadband. Public Power Council states that there is no forecast 

model that accurately predicts actual fluctuations in loads within the deviation band and 

therefore penalties will not induce parties to schedule more accurately. Public Power 

Council states that the 1.5 percent deviation band encourages loads to over-schedule and 

encourages the Commission to either expand the deviation band or adopt a multi-band 

system similar to the one Bonneville has in place. Snohomish notes that Bonneville has 

two deviation bands beyond the 1.5 percent that have greater penalties when customers 

cannot manage their energy imbalances within the first deviation band and states that this 
Docket Nos. RM05-25-000 and RM05-17-000 - 166 – 

approach seems equitable because it gives customers the proper incentives to keep their 

schedules accurate. 

231. Constellation argues that the Commission should eliminate energy imbalance 

penalties and require that imbalances be netted across all suppliers and with respect to 

each customer. EPSA contends that imbalances outside the deviation band should be 

netted on a system-wide basis and settled at incremental costs. Snohomish states that it 

prefers an approach that provides for netting and penalizes intentional deviation. Nevada 

Companies explains that its energy imbalance tariff nets all negative and positive 

imbalances such that penalties are only invoked if there is a net positive or a net negative 

imbalance outside of the deviation band. PPL also advocates that the Commission should 

allow suppliers the flexibility to net and trade imbalances in areas where no imbalance 

market exists. 

232. Duke contends that requiring transmission providers to supply imbalance service 

at a system incremental cost may eliminate the erroneous perception that the existing 

charges are discriminatory, but such an approach does nothing to solve the problems that 

imbalances cause, nor does such an approach reflect the actual costs of leaning on and 

dumping on the system. A number of commenters argue that penalties should be 

imposed because without penalties there is insufficient economic incentive for 
Docket Nos. RM05-25-000 and RM05-17-000 - 167 – 

transmission customers to properly schedule and, as such, reliability could be harmed.230 

WAPA states that if a balancing authority has very limited generation capacity (either 

physical or market) available for the provision of energy imbalance service, the 

assessment of penalties is warranted in order to establish a disincentive to improper 

behavior that potentially may affect reliability. 

233. Powerex notes that some mechanism should be in place that distinguishes between 

intentional or repeated deviations and unit outages or force majeure events and argues 

that penalties should be tiered so that they increase exponentially as a generator's 

imbalances increase. 

234. With regard to generator imbalances, EEI, Entergy, MidAmerican, and Southern 

contend that the Commission should continue its current policy, as established in Order 

No. 2003, of requiring that generator imbalances be addressed either in the OATT or in 

the generator interconnection agreement. EEI, MidAmerican and Entergy contend that 

the Commission should retain the flexibility of transmission providers to deal with the 

issue of generator imbalances on a case-by-case basis, subject to the requirement that 

they do not engage in unduly discriminatory or preferential treatment with respect to 

other generators on the system. Calpine contends that requiring transmission providers to 

treat generator imbalances in the pro forma OATT in the same way regardless of the 

 230 E.g., MidAmerican, NorthWestern, PacifiCorp, PNM-TNMP, Powerex, 

Progress Energy, Salt River, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 168 – 

generator, and in all control areas, would provide greater certainty and consistency for 

generators and help to eliminate the opportunity for transmission providers to engage in 

discriminatory behavior. Bonneville argues that its three-tiered pricing and penalty 

approach for energy imbalances also is appropriate for generator imbalances. 

235. PNM-TNMP states that the 1.5 percent deviation band for imbalance service 

continues to be appropriate except for intermittent resources. For those resources, it 

maintains, imbalance energy costs should not be punitive, but rather should be designed 

to allow the transmission provider to recover its full costs of providing the generator 

imbalance service. NRECA urges the Commission not to revise imbalance provisions in 

a manner that singles out wind generators for preferential treatment. Northwestern, on 

the other hand, argues that a generator imbalance service schedule should be included in 

the pro forma OATT for intermittent resources and the service should not apply to 

traditional generators. 

236. Commenters argue that the treatment of imbalances should be made comparable 

with the treatment of inadvertent energy for transmission providers. APPA argues that 

Schedule 4 raises concerns about discriminatory treatment because Schedule 4 is not 

applicable to OATT transmission providers, who clear their imbalances through the use 

of inadvertent interchange, if they operate their own control areas. TDU Systems 

contend that transmission providers that operate control areas hold a competitive 

advantage over non-control area operators solely by virtue of the fact that they have 

access to balancing options, such as inadvertent interchange, that are not available to all 
Docket Nos. RM05-25-000 and RM05-17-000 - 169 – 

market participants, including customers of the transmission providers. TDU Systems 

argue that this advantage can be decisive when sellers that do not operate control areas 

try to compete with control area operators for sales to entities concerned about exposure 

to the penalties imposed under existing imbalance tariff provisions.231 East Texas 

Cooperatives argue that control area utilities, moreover, enjoy a double benefit because: 

(1) they are not subject to penalties themselves, and (2) the control area operator’s own 

generation is used to provide imbalance service to the other transmission customers in the 

control area. TAPS asserts that comparability requires affording transmission dependent 

utilities the same return-in-kind treatment control areas use for inadvertent energy. It 

maintains that, at a minimum, the Commission should eliminate the $100/MWh penalty, 

except in egregious circumstances and/or the Commission should expand the return-inkind deviation band substantially. 

237. EEI and Entergy, on the other hand, argue that inadvertent energy and energy 

imbalances are not comparable and should thus be treated differently. EEI states that a 

NERC-certified control area is responsible for supporting the reliability of its own area as 

well as supporting the reliability of the interconnected power system grid. EEI explains 

that the inadvertent energy that a control area experiences reflects the moment-bymoment netting of load, generation and schedules into or out of the control area, and that 

 231 Accord APPA, Constellation, EPSA, Steel Manufacturers Association, and 

TAPS. 
Docket Nos. RM05-25-000 and RM05-17-000 - 170 – 

inadvertent energy reflects the loads, generator output and schedules of all entities within 

the control area, and not simply the loads and generation of the transmission provider. 

Entergy explains that control area interchange imbalances may involve the failure of 

control areas to match their scheduled inflows and outflows due to contingencies 

occurring even in another control area.232 

Discussion

238. The existing energy imbalance charges under Schedule 4 of the pro forma OATT 

and the generator imbalance charges described in Order No. 2003 are the subject of 

significant concern and confusion in the industry. The Commission is concerned 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 proposes 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. More specifically, the 

Commission seeks to 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, as well as the needs 

of a variety of transmission customers with different generator sources. 

239. To achieve this, the Commission proposes to create new energy and generator 

 232 Accord Progress Energy, Salt River, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 171 – 

imbalance schedules based on the following three principles: (1) the charges must be 

based on incremental cost or some multiple thereof; (2) the charges must provide an 

incentive for accurate scheduling, such as by increasing the percentage of the adder above 

(and below) incremental cost as the deviations become larger; and (3) the provisions must 

account for the special circumstances presented by intermittent generators and their 

limited ability to precisely forecast or control generation levels, such as waiving the more 

punitive adders associated with higher deviations. 

240. Bonneville has taken an energy imbalance pricing approach that appears consistent 

with the three principles outlined above and seems to be working well. Bonneville’s 

imbalance pricing approach is based on a three-tiered deviation band that would appear 

workable for both energy imbalance service and generator imbalance service. Under this 

proposal, 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 172 – 

overscheduling imbalances or 125 percent of the incremental cost for underscheduling 

imbalances. 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. 

241. The Commission seeks comment on whether this approach should be adopted for 

inclusion in the pro forma OATT for energy and generator imbalances. Does this 

approach provide 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? 

242. We note that the Bonneville provision allows for greater charges when a customer 

has an “intentional deviation.”233 We seek comment on whether the pro forma OATT 

imbalance provision should provide for penalties for behavior that represents deliberate 

reliance on the transmission provider’s generation resources, as opposed to scheduling 

 233 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. RM05-25-000 and RM05-17-000 - 173 – 

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. 

243. If the Commission adopts revised energy and generator imbalance schedules 

consistent with the principles proposed in this NOPR, that would eliminate the need for a 

final rule in the Imbalance Provisions Proceeding in Docket No. RM05-10-000 

concerning generator imbalance provisions for intermittent resources. As such, the 

Commission would expect to terminate that docket concurrent with the adoption of 

revised energy and generator imbalance schedules in this proceeding. 

244. With respect to the pricing of energy and generator imbalances, the Commission 

believes that charges based on incremental costs or multiples of incremental costs will 

provide the proper incentive to keep schedules accurate without being excessive. In 

deriving such charges, the Commission proposes that incremental cost be defined to 

include both energy and commitment234 costs (to the extent additional commitments are 

needed). The Commission seeks comment on how such charges should be calculated, as 

well as how they would be applied to transmission customers. How should additional 

demand and energy costs, if incurred in responding to imbalances, such as redispatch, 

commitment, or additional regulation reserves be appropriately reflected in the 

calculation of imbalance charges and which customers should be charged for such costs? 

 234 "Capacity commitment" generally is 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). 
Docket Nos. RM05-25-000 and RM05-17-000 - 174 – 

Who should receive any additional revenue from the charges above incremental costs? 

245. The Commission proposes to continue to allow inadvertent energy to be treated 

differently than energy and generator imbalances.235 The Commission believes that these 

two types of service are not comparable. 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 not 

simply the loads and generation of the transmission provider. Further, management of 

inadvertent energy is needed to adhere to NERC standards and to ensure reliability. 

Many of the variables of inadvertent interchange are beyond the control of individual 

transmission providers. Because of the nature of inadvertent energy and historical 

practices, transmission providers pay back imbalances in kind, and the Commission has 

accepted this treatment as just and reasonable. In contrast, allowing customers to pay 

back all energy and generator imbalances in kind would not provide sufficient incentives 

for them to minimize imbalances. Some commenters have argued that the return-in-kind 

approach to inadvertent energy between control areas is discriminatory because OATT 

customers are required to bear actual charges for their imbalances. As we have 

described, we believe the two services are different and hence do not believe that the two 

should have precisely the same treatment. However, we seek comment on whether the 

current return-in-kind approach to inadvertent energy encourages leaning on the grid in 

 235 See Order No. 888-A at 30,233. 
Docket Nos. RM05-25-000 and RM05-17-000 - 175 – 

times of shortage, and therefore whether any reforms in this area are appropriate. Would 

pricing inadvertent energy at incremental cost (or some variant thereof) be an appropriate 

disincentive? If any reforms in this area are appropriate, should they be pursued under 

FPA section 215 as part of the review of reliability standards? 

246. Furthermore, we propose 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.236 We also clarify 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. 

247. Finally, the Commission seeks 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. For example, if a 

transmission customer schedules 100 MWh over an hour but has a load of 120 MWh, it 

would face an imbalance of 20 MW. However, if it also dispatches its generation to the 

same 120 MWh, should there be no net charge? Similarly, what if a transmission 

 236 Imbalance Provisions Proceeding at 32,123 (citing Niagara Mohawk, 86 FERC 

at 61,028). 
Docket Nos. RM05-25-000 and RM05-17-000 - 176 – 

customer schedules 100 MWh but has a load of 80 MWh and dispatches its generation to 

80 MWh? Does the potential to allow netting for offsetting imbalances contradict the 

principle of encouraging good scheduling practices? We also seek 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. 

2. Credits for Network Customers 

248. 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. The section also states that new facilities are eligible for 

credits when the facilities are jointly planned and installed in coordination with the 

transmission provider. In the NOI, we asked several questions regarding the 

Commission's policy on credits for new facilities, including whether the Commission 

should reconsider its policy of denying credits for transmission facilities owned by pointto-point customers. 
Docket Nos. RM05-25-000 and RM05-17-000 - 177 – 

 Comments

249. Many commenters argue that the existing credit requirement has the effect of 

discouraging joint transmission planning.237 NRECA asserts that making the existence of 

joint planning a condition of a customer’s eligibility for credits or revenue requirement 

recovery simply provides another excuse for public utility transmission providers to 

refuse to engage in joint planning. 

250. EEI contends that if the transmission provider is required to provide credit against 

the customer’s cost of transmission service, the cost of the customer’s jointly planned and 

integrated transmission facilities should be automatically added to the transmission 

provider’s cost of service. EEI states that the Commission has adopted a similar 

approach with respect to third party supply of reactive capability. EEI also argues that 

automatic credit for customer facilities is inappropriate because in instituting open access 

and requiring transmission providers to offer network service, the Commission made it 

clear that it did not direct a merging of the parties’ transmission systems or the operation 

of a joint transmission network.238 EEI argues that the Commission should retain the 

 237 E.g., Arkansas Cities, East Texas Cooperatives, Nevada Companies, NRECA, 

PNM-TNMP, Suez Energy NA, TAPS, TransAlta, TDU Systems, and Xcel. 

238 For support, EEI cites Florida Municipal Power Agency v. Florida Power & 

Light Co., 74 FERC ¶ 61,006 at 61,009-10 (1996), order on reh’g, 96 FERC ¶ 61,130 

(2001), aff’d sub nom. Florida Municipal Power Agency v. FERC, 315 F.3d. 362 

(D.C. Cir. 2003). 
Docket Nos. RM05-25-000 and RM05-17-000 - 178 – 

requirement that customer transmission facilities are eligible for credits from 

transmission providers other than RTOs and ISOs only if they meet the integration 

standard. 

251. Some commenters argue that the OATT should not be reformed to include credits 

for transmission facilities built by point-to-point customers.239 EEI states that the 

question posed in the NOI appears to contemplate providing credits to a point-to-point 

customer who constructs new facilities that are jointly planned with the transmission 

provider regardless of whether those facilities meet the Commission’s standards for 

integration of customer-owned transmission facilities. Instead, EEI argues, the 

Commission should apply the test from Consumers Energy Co., which provides that a 

transmission customer should receive credits against its transmission bill when the 

transmission provider uses facilities owned by that customer to provide service to other 

transmission customers.240 Bonneville and PNM-TNMP state that if applied to existing 

facilities, credits for point-to-point customers could cause major cost shifts. Bonneville 

argues that these problems would be especially severe in the Northwest, where there are 

numerous areas of multiple transmission ownership, both in series and in parallel, and 

where transmission owners purchase large amounts of transmission from each other. 

 239 E.g., Bonneville, EEI, and PNM-TNMP. 

240 EEI cites Consumers Energy Co., 86 FERC ¶ 63,004 at 65,016 (1999), order on 

initial decision, 98 FERC ¶ 61,333 (2002) and Northeast Texas Electric Cooperative, 

Inc., 111 FERC ¶ 61,189 at P 6 (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 179 – 

Southern states that to effectuate this proposal, the Commission would need to revise its 

“higher of” pricing requirements, otherwise no point-to-point customer would build 

transmission facilities when it can require the transmission provider to do so and costs are 

rolled into rate base. Entergy opposes providing credits for transmission facilities owned 

by point-to-point service customers because those facilities are not used to integrate 

resources and loads in the same way that facilities owned by network customers are. 

252. Other commenters argue that the Commission should modify the pro forma OATT 

to include a provision allowing credits for transmission facilities built by a point-to-point 

customer.241 TAPS states the Commission should re-evaluate its bright line denial of 

credits for transmission facilities owned by point-to-point customers. TAPS contends 

that the current section 30.9 integration test may be appropriate for long-term (e.g., at 

least 5 years) point-to-point customers. South Carolina E&G supports modifying the pro 

forma OATT to provide credits for facilities built by point-to-point customers, but asserts 

that credits should apply only when the customer’s facilities are in service. South 

Carolina E&G states that after the passage of a defined period of inactivity, such as when 

a customer takes a facility out of service, the credits should be suspended, to reduce the 

burden on other customers. 

 241 E.g., MidAmerican, South Carolina E&G, TAPS, and Williams. 
Docket Nos. RM05-25-000 and RM05-17-000 - 180 – 

Discussion

253. Section 30.9 of the pro forma OATT establishes two categories of facilities owned 

by network customers that are eligible for credits. First, existing transmission facilities 

"integrated with the Transmission Provider's Transmission Systems," are eligible for 

credits 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." The second category comprises new facilities (i.e., 

facilities constructed by the network customer after the service commencement date in 

the OATT), if the facilities "are jointly planned and installed in coordination with the 

Transmission Provider." 

254. We agree with the commenters who argue that section 30.9 should be reformed. 

We agree 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 if it believes that the cost of any facilities 

constructed as a result of that process will have to be borne in significant part by its 

bundled retail customer. 

255. Therefore, we propose to sever the link between credits and planning, and treat the 

two issues separately within the pro forma OATT.242 Eliminating the link is appropriate 

 242 See Part V.B for a discussion of our proposed planning obligations. 
Docket Nos. RM05-25-000 and RM05-17-000 - 181 – 

because the crediting of integrated facilities serves a purpose independent of the planning 

obligation. Traditionally, the Commission has allowed a transmission provider to 

allocate the costs of integrated facilities to all users of the integrated system or grid 

consistent with the view that the entire grid is interconnected and provides generalized 

benefits to all users.243 But because integration is a fact-specific matter, the Commission 

in Order No. 888 decided that credits were appropriately addressed on a case-by-case 

basis. 244 

256. Regarding the eligibility for credits, as the Commission stressed in Order No. 888, 

while certain facilities may warrant some form of cost credit, the mere fact that 

transmission customers may own transmission facilities is not a guaranteed entitlement to 

such credit.245 Rather, a network customer's transmission facilities must provide 

additional benefits to the transmission grid in terms of capability, delivery options, and 

reliability, and be relied upon for the coordinated operation of the grid. 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 

 243 See, e.g., Pacific Gas and Electric Co., 106 FERC ¶ 61,144 at P 12, reh’g 

denied, 108 FERC ¶ 61,297 (2004); Niagara Mohawk Power Corp., 42 FERC ¶ 61,143 at 

61,531 (1988); Otter Tail Power Co., 12 FERC ¶ 61,169 at 61,420 (1980). 

244 Order No. 888 at 31,742. 

245 Order No. 888 at 31,742-43. 
Docket Nos. RM05-25-000 and RM05-17-000 - 182 – 

grid in terms of capability and reliability and can be relied on by the transmission 

provider for the coordinated operation of the grid."246 This policy is premised on the 

principle that "just as the transmission provider cannot charge the customer for facilities 

not used to provide transmission service, the customer cannot get credits for facilities not 

used by the transmission provider to provide service."247 The Commission continues to 

believe that, for existing facilities, the integration standard is the appropriate standard for 

determining whether a network customer's facilities should be eligible for credits. We 

clarify, however, that for new facilities, the integration standard must be applied 

comparably,248 because application of the integration test in a manner that exclusively 

 246 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). 

247 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). 

248 In Order No. 888, the Commission addressed the comparability requirement: 

We caution all transmission providers that while our discussion here addresses the 

requirements necessary for a customer’s transmission facilities to become eligible 

for a credit, the principles of comparability compel us to apply the same standard 

to the transmission provider’s facilities for rate determination purposes. 

Order No. 888 at 31,743 n.452. 
Docket Nos. RM05-25-000 and RM05-17-000 - 183 – 

benefits the transmission provider is unduly discriminatory, and a violation of the FPA.249 

Specifically, we propose that the network customer shall receive credit for transmission 

facilities added subsequent to the effective date of the Final Rule in this proceeding 

provided that: (1) such facilities are integrated into the operations of the transmission 

provider’s facilities, and (2) if the transmission facilities were 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. 

257. Thus, the Commission proposes revising section 30.9 to eliminate the disincentive 

to coordinated planning and investment in the transmission grid (i.e., by deleting 

language that permits transmission providers to refuse crediting for network-customerowned facilities that are not part of its planning process) and provide for nondiscriminatory crediting for integrated facilities comparable to those transmission 

provider facilities that are included in rates. We are proposing this change to ensure that 

section 30.9 does not impede coordinated planning and to otherwise ensure that our 

crediting policy is just, reasonable and not unduly discriminatory. Our action is not in 

 249 Credits may not be necessary if the transmission provider and a transmission 

customer jointly own the transmission facilities and operate those facilities under the 

terms of a joint ownership agreement. See Northern States Power Co., 83 FERC 

¶ 61,098 at 61,472 (explaining that the crediting provision in pro forma OATT 

section 30.9 was not intended to apply to jointly owned transmission facilities), order on

clarification, 83 FERC ¶ 61,338, order denying reh'g and clarification, 84 FERC ¶ 61,122 

(1998), remanded on other grounds sub nom. Northern States Power Co. v. FERC, 

176 F.3d 1090 (8th Cir. 1999). 
Docket Nos. RM05-25-000 and RM05-17-000 - 184 – 

any way intended to lessen our commitment to coordinated planning between a 

transmission provider and its customers. To the contrary, we propose elsewhere in the 

NOPR to require coordinated planning by all transmission providers. This requirement is 

not linked to the issue of crediting for customer-owned facilities, but rather is a general 

requirement intended to avoid opportunities for undue discrimination in transmission 

planning. 

258. We decline to allow transmission providers as part of this proceeding to 

automatically add 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. Nevertheless, 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 section 205 of the 

FPA.250 

259. Finally, the Commission does not propose revising the pro forma OATT to 

expressly allow transmission credits for facilities owned by point-to-point customers. 

Unlike a network customer, a point-to-point customer only pays for a discrete 

transmission service over the contract term. The 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 

 250 See, e.g., id. at 61,467. 
Docket Nos. RM05-25-000 and RM05-17-000 - 185 – 

and loads in its long-term planning horizon and the two parties coordinate operations of 

their facilities through a network operating agreement. In this way, network service is 

comparable to the service that the transmission provider uses to serve its own retail native 

load, and credits for certain integrated network facilities are appropriate. The point-topoint customer, however, does not purchase integration service, nor does it sign a 

network operating agreement with the transmission provider. Thus, because of the 

inherent differences between point-to-point and network service, we do not propose 

adding a new OATT requirement that the transmission provider make credits generically 

available to point-to-point customers that own transmission facilities. Nevertheless, there 

may be some facilities owned by a point-to-point customer that meet all the criteria for 

credits. Although the Commission is not including a specific provision in the OATT that 

provides credits for these facilities, consistent with the Commission's statement in Order 

No. 888, the Commission will address such situations on a fact-specific, case-by-case 

basis.251 

3. Capacity Reassignment 

260. In Order No. 888, the Commission concluded that a public utility's tariff must 

explicitly permit the voluntary reassignment of all or part of a holder's firm point-to-point 

capacity rights to any eligible customer.252 As for the rate for capacity reassignment, the 

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

252 Order No. 888 at 31,696; pro forma OATT section 23.1. 
Docket Nos. RM05-25-000 and RM05-17-000 - 186 – 

Commission concluded that it could not permit reassignments at market-based rates 

because it was unable to determine that the market for reassigned capacity was 

sufficiently competitive so that assignors would not be able to exert market power. 

Instead, the Commission capped the rate at the highest of: (1) the original transmission 

rate charged to the purchaser (assignor), (2) the transmission provider's maximum stated 

firm transmission rate in effect at the time of the reassignment or (3) the assignor's own 

opportunity costs capped at the cost of expansion (price cap).253 

261. The Commission explained in Order No. 888 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)."254 

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.255 As a result, the Commission 

required that assignors proposing to recover opportunity costs file with the Commission a 

fully developed formula describing the derivation of opportunity costs. The Commission 

 253 Order No. 888 at 31,697. 

254 Id. at 31,740. 

255 Order No. 888-A at 30,224. 
Docket Nos. RM05-25-000 and RM05-17-000 - 187 – 

further required that all information necessary to calculate and verify opportunity costs 

must be made available to the eligible customer.256 

262. In the NOI, the Commission asked whether the price cap remained reasonable, or 

whether it should be modified or eliminated to further encourage capacity reassignment. 

Comments

263. Some commenters argue that the price cap should not be eliminated.257 According 

to EEI, transmission pricing policies do not have much impact on reassignment of 

capacity rights, so changes to the approach would be largely irrelevant. 

264. Southern contends that elimination of the price cap might result in inefficiencies 

by providing an incentive for entities to hoard transmission capacity. Moreover, Tacoma 

and Public Power Council reason that because transmission remains a monopoly 

business, cost-based rates remain appropriate. 

265. Snohomish expresses concern that eliminating the price cap may encourage 

speculation in the purchase of transmission capacity, greatly driving up costs for 

transmission customers. Snohomish, nonetheless, states that auctions of secondary 

capacity may be appropriate, provided the capacity is purchased under a long-term 

contract for the purpose of serving load and the sale does not reduce transmission 

capacity for existing customers that have contracted for the capacity. 

 256 See id.; Order No. 888 at 31,740. 

257 E.g., Ameren, EEI, Southern, and Tacoma Power. 
Docket Nos. RM05-25-000 and RM05-17-000 - 188 – 

266. Other commenters argue that the price cap should be revised.258 Exelon supports 

the maximum flexibility possible in use of the transmission system, including allowing 

transmission rights to be assigned and redirected – so long as the transfer capability is 

available and existing service will not be curtailed. Exelon recommends that the 

Commission modify the OATT to permit transmission customers to charge market-based 

rates for transmission capacity in the secondary market. This change, Exelon argues, 

would provide greater incentive for the owner of the transmission right to actively pursue 

reassigning the transmission service, thereby using the transfer capability more 

efficiently. Alcoa states that economic incentives are needed to enable a secondary 

transmission capacity market to develop and thrive. 

267. EPSA and Constellation argue that the only desirable modification to this pricing 

policy would be to eliminate the requirement that transmission customers file with the 

Commission a method to impose opportunity cost pricing. EPSA states that to its 

knowledge, no transmission customer has yet been able to develop and file a predefined 

formula mechanism that would serve as an opportunity cost rate, probably because 

opportunity cost pricing reflects dynamic market conditions. MidAmerican claims that 

even when there is no disagreement over the assignor’s determination of opportunity 

costs, considerable time may be required to prepare and obtain approval from the 

Commission of the resulting FPA section 205 filing. EPSA asserts that the market itself 

 258 E.g., Alcoa, Constellation, EPSA, Exelon, and MidAmerican. 
Docket Nos. RM05-25-000 and RM05-17-000 - 189 – 

will cap the value of reassignment at the price the transmission provider would charge, 

i.e., its expansion cost. Constellation states that prices of reassigned capacity will be 

disciplined by the opportunity costs of releasing the capacity. Both Constellation and 

EPSA state that the Commission should recognize that opportunity costs for released 

transmission capacity are dynamic and provide a market discipline on the price that any 

seller will charge and any purchaser will pay for reassigned capacity. In response to 

EPSA’s proposal to eliminate the requirement that transmission customers file with the 

Commission a method to impose opportunity cost pricing, APPA argues that to ensure 

that the price a seller would charge for firm transmission capacity is just and reasonable, 

as the FPA requires, the Commission should require such a filing. 

268. While Cinergy maintains that the current pricing approach for capacity 

assignments is appropriate, it supports consideration of new alternatives that would allow 

more effective capacity reassignment by the transmission customer. Cinergy asserts that 

one area that could be considered is to require the transmission provider to provide more 

clarity on how reassignment requests are analyzed for approval and the options available 

to the transmission customer to post existing service for reassignment. 

269. Williams and Powerex argue that revising the price cap will not encourage greater 

capacity reassignment. Williams submits that other non-price limitations on capacity 

reassignment – such as the requirement that the assignee utilize the same source and sink 

as the original customer – are the real reasons there has not been more capacity 
Docket Nos. RM05-25-000 and RM05-17-000 - 190 – 

reassignment. Stated differently, Williams contends that the price cap does not restrict 

capacity reassignment – source and sink requirements do. 

Discussion

270. In Order No. 888, the Commission explained that it expected capacity 

reassignment to achieve three goals: "(1) help [customers] manage the financial risks 

associated with their long-term transmission commitments, (2) reduce the market power 

of transmission providers by enabling customers to compete, and (3) foster efficient 

capacity allocation."259 Because capacity reassignment does not appear to have 

developed into a competitive alternative to primary capacity, the Commission is 

proposing modifications to its existing pricing policy. We propose removing the price 

cap on capacity reassignment and allowing negotiated rates for transmission capacity 

reassigned by transmission customers. We do not propose to lift the price cap for 

capacity resold by transmission providers or their affiliates due to market power 

concerns. 

271. The Commission notes that transmission customers have not used the opportunity 

cost pricing option for capacity reassignment. Comments suggest that this may be due in 

part to the complexity of establishing an opportunity cost formula, or the administrative 

hurdle of filing and supporting a proposal. Simply put, the goals of the capacity 

assignment program remain important to the Commission, but the price cap has not 

 259 Order No. 888 at 31,696. 
Docket Nos. RM05-25-000 and RM05-17-000 - 191 – 

served as a useful means of achieving them. While we recognize that other factors may 

inhibit capacity reassignment, eliminating the price cap should provide more flexibility to 

market participants and encourage customers to sell their capacity to another customer 

who values the capacity more highly. It also will facilitate the release of capacity and 

encourage the maximum number of voluntary transactions to occur in a secondary 

market, which will benefit all market participants consistent with the Commission's goals 

for capacity reassignment. 

272. Although in Order No. 888 the Commission decided not to allow reassignment at 

market-based rates because of concerns that capacity assignors might exert market power, 

due to several factors, we now believe that market forces will limit the ability of most 

assignors to exert market power. First, we expect that competition among releasing 

customers will restrict the potential exercise of market power. Second, the Commission 

will monitor the market by requiring quarterly reports and regular OASIS postings from 

transmission providers based on information submitted to them from reassigning 

customers regarding their reassignment activity (including the negotiated rate). The 

Commission’s complaint procedures and the Enforcement Hotline also are available for 

participants raising market power concerns, which should supplement the Commission’s 

existing market oversight efforts. Third, the continued regulation of rates for primary 

capacity will act as a check to ensure just and reasonable reassignment rates. For 

example, without congestion on the transmission system, the transmission provider's rate 

on file serves as the de facto price cap and, if congestion exists, the "incremental rate," 
Docket Nos. RM05-25-000 and RM05-17-000 - 192 – 

which reflects the transmission provider’s cost of expansion, should act as a price ceiling 

for long-term transactions. 

273. The Commission concludes that because the price cap appears to have reduced 

customers’ transmission options, removal of the price cap is warranted without a marketby-market analysis. Our reform is intended to provide alternatives for customers that 

value the capacity more highly. The Commission finds that lifting the price cap strikes a 

reasonable balance between promoting more efficiency through trading and relying upon 

competition and price disclosure to prevent anticompetitive behavior. Though we 

recognize that the price of reassigned capacity may temporarily exceed the cost of 

expansion, that price signal is an important economic incentive to induce greater 

transmission investment. 

274. Concerns have been raised that allowing negotiated rates may provide an incentive 

to “hoard” capacity, or to reserve transfer capability for no legitimate use other than to 

speculate on the price of the reassigned capacity. The ability of a transmission customer 

to hoard capacity is not without limits in that the transmission provider has the obligation 

to resell as non-firm point-to-point service any firm point-to-point transfer capability 

reserved by a customer but not scheduled within the time-frames established in pro forma

OATT section 13.8. As discussed above, we believe that the incentive for the 

transmission customer to hoard would be limited by the transmission provider’s cost of 

expansion for long-term transactions. Thus, we believe that the greater efficiency created 

by a more effective capacity trading market for customers who need capacity during peak 
Docket Nos. RM05-25-000 and RM05-17-000 - 193 – 

periods outweighs such concerns and that hoarding concerns are overstated. However, 

we seek comment on whether circumstances exist where unaffiliated transmission 

customers could amass market power similar to that of the transmission provider. 

275. We do not propose lifting the price cap for all assignors. A stated goal of capacity 

reassignment is to “reduce the market power of transmission providers by enabling 

customers to compete.”260 Commission precedent has allowed transmission provider 

affiliates to reassign capacity under the price cap,261 and we propose to continue this 

policy. To allow transmission providers and their affiliates to use negotiated rates allows 

the transmission provider to use its primary market power in the secondary market. A 

transmission provider not subject to a price cap would have the ability and incentive to 

exercise market power to favor its own generation sales when it operates and administers 

the reassignment process. Furthermore, lifting the cap for the transmission provider may 

eliminate the incentive to build or expand, as it may allow the transmission provider to 

take advantage of congested pathways to charge rates above the cost of expansion. 

Because these expected outcomes would reduce the ability of other customers to 

compete, and undermine the development of a viable secondary market, we conclude that 

it remains appropriate to require transmission providers and their affiliates to conform to 

the price cap for capacity reassignment. 

 260 Id. 

261 Commonwealth Edison Co., 78 FERC ¶ 61,312 at 62,336 (1997). 
Docket Nos. RM05-25-000 and RM05-17-000 - 194 – 

276. The Commission seeks comment on the quarterly reports and OASIS postings we 

propose to require from transmission providers under this proposal. They will be based 

on information that we will require assignors to give to transmission providers. What 

information should we require 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? Is other 

information necessary for operational and reliability purposes? Are additional reports by 

assignors to the transmission provider necessary, and if so, what information should be 

reported by assignors? Should the Commission establish a new quarterly reporting 

process, e.g., a new form, or utilize the existing electronic electric quarterly report 

procedures? How frequently should the OASIS postings be made? 

4. “Operational” Penalties 

a. Unauthorized Use Penalties

277. Section 13.7 of the pro forma OATT stipulates that a point-to-point service 

customer’s use of the transmission system may not exceed the firm capacity it has 

reserved at each point of receipt and each point of delivery except as specified in 

section 22 of the pro forma OATT.262 Section 13.7 of the pro forma OATT also directs 

 262 Section 22 (Changes in Service Specifications) of the pro forma OATT 

prescribes the circumstances under which the transmission customer may modify the 

point of delivery and the point of receipt for an existing firm point-to-point service 

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

the transmission provider to specify the rate treatment and all related terms and 

conditions for an unauthorized use operational penalty in the event that a point-to-point 

customer exceeds its firm reserved capacity at any point of receipt or point of delivery. 

Section 14.5 of the pro forma OATT contains similar provisions for an unauthorized use 

penalty in the event that a transmission customer exceeds its non-firm point-to-point 

service capacity reservation. The pro forma OATT does not otherwise address 

unauthorized use penalties. 

278. In Allegheny Power, the Commission capped unauthorized use penalties at a level 

equal to twice the standard rate for the service at issue.263 In addition, the Commission 

clarified that the standard rate to be used as the basis of the unauthorized use penalty 

charge must be that of the service at issue, without regard to the duration of the violation; 

i.e., if overuse occurs for one hour, but the service overused is weekly service, the penalty 

charge is to be capped at twice the standard weekly rate.264 In APS, the Commission 

issued an audit report to Arizona Public Service Company (APS) that contains two 

findings that Commission audit staff characterized as unauthorized use of transmission 

service.265 In the first finding, APS’s wholesale merchant function did not request and 

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

(Allegheny Power). 

264 Id. at 61,546 n.131. 

265 Arizona Public Service Co., 109 FERC ¶ 61,271 at P 6 (2004) (APS). 
Docket Nos. RM05-25-000 and RM05-17-000 - 196 – 

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. Other than these cases, the Commission has not addressed the appropriate 

method of applying unauthorized use penalties pursuant to the provisions of sections 13.7 

and 14.5 of the pro forma OATT. 

Comments

279. MidAmerican states that unauthorized use penalties should only be imposed if the 

pro forma OATT clearly specifies that they are applicable to a proscribed conduct. 

Discussion

280. We propose to clarify the circumstances under which we would expect 

transmission providers to assess unauthorized use penalties. This clarification 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 obligations imposed by it. 

Specifically, we propose to clarify that unauthorized use penalties apply to any 

circumstance when a transmission customer uses transmission service that it has not 
Docket Nos. RM05-25-000 and RM05-17-000 - 197 – 

reserved.266 An unauthorized use penalty would be assessed in circumstances when a 

transmission customer has a transmission service reservation, but uses transmission 

service in excess of its reserved capacity. An unauthorized use penalty also would be 

assessed if a transmission customer uses transmission service when it does not have a 

transmission service reservation, including the situations described in APS. We further 

clarify that an unauthorized use penalty would not be assessed in circumstances when a 

transmission customer inappropriately uses a network service reservation to support an 

off-system sale, as discussed in Part V.D.7. However, a transmission customer that 

inappropriately uses network service would be required to pay for the point-to-point 

service it should have reserved and could be subject to a civil penalty depending on the 

circumstances. We seek comment on whether the current policy that limits unauthorized 

use penalties to twice the standard rate for the service at issue has resulted in penalties 

that are not just and reasonable; and, if so, we seek comment regarding provisions that 

would yield unauthorized use penalties that are just and reasonable. 

b. How Transmission Providers Should Pay Operational 

Penalties

Comments

281. In the NOI, the Commission observed that the existing pro forma OATT allows 

transmission providers to impose certain operational penalties against transmission 

 266 The revised pro forma OATT reflects this proposed reform in sections 13.7 and 

30.4. 
Docket Nos. RM05-25-000 and RM05-17-000 - 198 – 

customers for violations of the pro forma OATT, but does not address the adverse 

consequences to a transmission provider who violates its OATT. 

282. Several commenters indicate that a transmission provider would not face the same 

financial consequence as other transmission customers when the transmission provider or 

an affiliated transmission customer pays an operational penalty. TAPS notes that 

applying customer-focused penalties to the transmission provider is meaningless if a 

transmission provider merely pays itself. EPSA suggests that the Commission include 

provisions in the new pro forma OATT to ensure that the penalty imposes a true financial 

consequence, e.g., penalties imposed on a transmission provider should be distributed to 

those OATT customers that were taking service during the period in which the violation 

occurred. ELCON suggests that the pro forma OATT be revised to provide for tariffbased sanctions against a transmission provider that fails to comply with its OATT. 

Occidental argues that one of the fundamental problems with the current OATT is the 

lack of tariff-based penalties for violations. Occidental states that tariff-based penalties 

are needed to focus transmission providers on compliance and to permit customers and 

the Commission’s enforcement staff to bring both specific tariff violations and general 

issues of non-compliance before the Commission. 

Discussion

283. We propose to have transmission providers pay non-offending, unaffiliated 

transmission customers when the transmission provider or its affiliate incurs operational 

penalties. This proposal is consistent with our prior findings that operational penalties 
Docket Nos. RM05-25-000 and RM05-17-000 - 199 – 

collected by the transmission provider should be credited back to non-offending 

transmission customers in order to provide an incentive to the transmission provider to 

develop non-penalty remedies that will elicit appropriate behavior by transmission 

customers.267 For those transmission providers subject to operational penalties, we 

propose to require the transmission provider to make an annual compliance filing to 

notify the Commission of the amounts of all 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, we propose 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 non-offending, 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. We also propose to prohibit transmission providers from 

recovering for ratemaking purposes or through any service or facility under the Commision’s jurisdiction any cost it incurs when it or an affiliate pays an operational penalty. 

 267 See, e.g., Carolina Power & Light Co., 103 FERC ¶ 61,209 (2003); 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 31,315 (2000) (noting that “to the extent that penalty revenues 

are generated, the required crediting of penalty revenues will eliminate any economic 

incentive for pipelines to rely on penalties rather than inducements”); order on reh'g, 

Order No. 637-A, 65 FR 35705 (Jun. 5, 2000), FERC Stats. & Regs. ¶ 31,099 (2000). 
Docket Nos. RM05-25-000 and RM05-17-000 - 200 – 

5. “Higher of” Pricing Policy

284. 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.268 The Commission 

has explained that when rolling in the costs of network upgrades incurred to meet a 

transmission service request would have the effect of raising the average embedded cost 

rate paid by existing customers, the transmission provider may elect to charge an 

incremental cost rate for the new service and thereby insulate existing customers from the 

costs of any necessary system upgrades. However, the transmission provider may not 

charge both an incremental cost rate and an embedded cost rate associated with existing 

network transmission facilities.269

 268 Inquiry Concerning the Commission’s Pricing Policy for Transmission Services 

Provided by Public Utilities Under the Federal Power Act, Policy Statement, 59 FR 

55031at 55037 (Nov. 3, 1994), FERC Statutes and Regulations ¶ 31,005 at 31,146 

(1994), order on reconsideration, 71 FERC ¶ 61,195 (1995) (Transmission Pricing Policy 

Statement). 

269 See Northeast Utilities Service Company (Re: Public Service Company of New 

Hampshire), Opinion No. 364-A, 58 FERC ¶ 61,070 (1992), reh'g denied, Opinion 

No. 364-B, 59 FERC ¶ 61,042, order granting motion to vacate and dismissing request 

for rehearing, 59 FERC ¶ 61,089, aff'd in part and remanded in part sub nom. Northeast 

Utilities Service Company v. FERC, 993 F.2d 937 (1st Cir. 1993), order on remand, 

66 FERC ¶ 61,332, reh'g denied, 68 FERC ¶ 61,041 (1994) pet. denied; Pennsylvania 

Electric Co., 58 FERC ¶ 61,278, reh'g denied, 60 FERC ¶ 61,034 (clarifying pricing 

policy), reh'g denied, 60 FERC ¶ 61,244 (1992), aff'd sub nom. Pennsylvania Electric 

Co. v. FERC, 11 F.3d 207 (D.C. Cir. 1993). 
Docket Nos. RM05-25-000 and RM05-17-000 - 201 – 

285. Although we are not undertaking generic transmission pricing reform in this 

proceeding, we are concerned that our existing policies may not be being applied 

consistently and, as a result, customers may be quoted prices that are not consistent with 

the “higher of” policy. We understand that customers typically are quoted an incremental 

rate in the form of a total dollar amount of needed facility upgrades (e.g., $5,000,000) 

rather than in the form of a monthly transmission rate that can be compared, on an 

“apples-to-apples” basis, to the embedded cost rate. Presenting an incremental rate as a 

lump sum payment request is inconsistent with our ratemaking policy and has the 

potential to discourage customers from proceeding with service requests. 270 As we have 

noted, under our “higher of” pricing policy for network upgrades, the transmission 

provider should compare the monthly revenue requirement from the upgrade to the 

monthly revenue requirement from the embedded transmission rate.271 We also have said 

that the incremental rate should be established by amortizing the cost of the upgrades 

over the life of the contract.272 Presenting the incremental charge in the form of a 

 270 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). 

271 Southwest Power Pool, Inc., 112 FERC ¶ 61,319 at P 33 (2005). 

272 Southwest Power Pool, Inc., 98 FERC ¶ 61,256 (“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.”); reh’g denied in pertinent 

part, 100 FERC ¶ 61,096 (2002). 
Docket Nos. RM05-25-000 and RM05-17-000 - 202 – 

monthly rate allows a customer seeking a lower rate to choose to request a longer 

transaction term. 

286. We encourage comments on whether changes to the pro forma OATT are 

necessary to ensure that incremental costs are presented as monthly rates for service. 

D. Non-Rate Terms and Conditions

287. In this section, we propose a number of reforms to non-rate terms and conditions 

of service under the pro forma OATT. We propose these reforms to eliminate 

opportunities for undue discrimination, to ensure that the services offered under the pro 

forma OATT are just and reasonable, to increase the transparency of service being 

provided, and to provide clarity with respect to terms and conditions that have caused 

confusion in the industry. 

1. Potential Modifications to Long-Term Firm Point-to-Point 

Service 

288. In Order No. 888, the Commission required all public utilities to offer both firm 

and non-firm point-to-point service and firm network service on a non-discriminatory 

open access basis.273 In the NOI, the Commission asked for comments on pricing 

policies that can create an incentive to maximize the use of the transmission system.274 

Also, the Commission asked whether the OATT should require transmission providers to 

offer new transmission services, such as conditional firm, partial firm, and seasonal firm 

 273 Order No. 888 at 31,690. 

274 NOI at P 13. 
Docket Nos. RM05-25-000 and RM05-17-000 - 203 – 

service.275 Further, the Commission asked in the NOI whether deviations from the 

“higher of” pricing policy would encourage greater incremental pricing of redispatch 

service.276 

Comments

289. Some commenters support the inclusion of a required new service and contend 

that the existing rules for long-term firm point-to-point service pose barriers to new entry. 

Constellation states that new products are needed that facilitate the efficient use of the 

transmission system in a competitive market. AWEA and EPSA argue that a long-term 

request for service from a new generator can be denied because there are reliability 

violations in only a few hours of a year, even though firm service is nonetheless available 

for the large majority of hours of the year. They also argue the existing grid is 

underutilized and that these practices only exacerbate this problem. EPSA further states 

that some transmission provider base case models show that the transmission provider is 

operating its system to serve its bundled retail native load under contingencies that the 

transmission provider would not accommodate for an OATT customer. 

290. PPL argues that the Commission should enforce the requirement in section 13.5 of 

the pro forma OATT that transmission providers must redispatch to relieve congestion 

that may only occur during a few hours a year. PPL further contends that transmission 

 275 Id. at P 13. 

276 Id. at P 12. 
Docket Nos. RM05-25-000 and RM05-17-000 - 204 – 

providers have the incentive to simply deny requests for transmission over a path that 

experiences occasional congestion, rather than properly undertake redispatch actions to 

minimize this congestion. Others state that they have not received an offer by a 

transmission provider to redispatch to accommodate a request for transmission service, 

but instead are given no choice but to pay for facilities studies that are costly and time 

consuming.277 Entergy states in its reply comments that it only evaluates redispatch as 

part of a system impact study if requested by the transmission customer. 

291. Several commenters suggest that pricing complexities and certainty of recovery 

must be resolved before requiring mandatory redispatch. These commenters state that the 

cost of redispatch is more than the fuel cost differential and includes hard to quantify 

costs such as start-up costs, higher capital costs due to shorter life and accelerated 

replacement, higher maintenance costs, and potential emergency power purchases to 

serve load in constrained areas.278 

292. PacifiCorp suggests that the higher charge, whether embedded costs or redispatch 

costs, be determined on a monthly basis rather than making a one-time determination 

prior to commencement of service. PacifiCorp argues that the typical cost analysis fails 

to consider the complexity of determining redispatch. PacifiCorp contends that cost 

estimates become increasingly unreliable as the analysis extends over time, and the 

 277 E.g., AWEA, Arkansas Cities, EPSA, and Renewable Energy. 

278 E.g., Ameren, EEI, Progress Energy, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 205 – 

complications of one-year transmission service agreements with rollover options make an 

accurate calculation nearly impossible. 

293. AWEA provides a detailed proposal for conditional firm service, in which the 

transmission provider would identify certain months, weeks, or days when firm 

transmission service may be limited or unavailable and identify the number of potential 

hours during those conditional times, when the customer could have its reservations cut 

or reduced prior to any firm customer reductions. Under specified conditions, for a 

limited number of hours over a set number of “conditional” months, weeks, days or 

hours, the firm service may be reduced day-ahead by the transmission provider, with 

conditional firm service provided instead in those hours firm service is unavailable. The 

“conditional” periods would be established when the service is offered. Also, capacity 

commitments for conditional firm service would be accounted for in ATC calculations 

prior to new sales of short-term firm transmission service. Commenters support a 

requirement that transmission providers post on OASIS the paths for which conditional 

firm service is available, clearly listing the available capacity for each period, and hours 

during which firm service is available or curtailment is possible as a result of 

congestion.279

 279 E.g., EPSA and PPL. 
Docket Nos. RM05-25-000 and RM05-17-000 - 206 – 

294. Those supporting conditional firm service argue that it should be offered to 

customers requesting long-term firm service when firm ATC is not available during all 

hours of the request, and allow the transmission customer to obtain service when it would 

otherwise be denied.280 As for the rate design of the service, EPSA and PPL recommend 

that it include either a discount from the firm rate to reflect the reduction in use at the 

system peak or no discount from the firm rate, but customers taking conditional firm 

service would have a right of first refusal when firm service becomes available for the 

hours in which they have agreed to be curtailed. 

295. Commenters arguing against a requirement to provide conditional firm service 

argue that it would degrade the quality of service received by existing long-term firm 

point-to-point and network customers.281 Also, Bonneville argues that providing 

conditional firm service would require modification to the current curtailment priorities 

in the OATT and the design and purchase of systems to track the purchases and 

implement the more complex curtailment schemes. TAPS notes that PacifiCorp amended 

its OATT to make more explicit the potential for granting part of a request for firm 

service in terms of both the amounts of service and/or the periods of time for which there 

 280 E.g., AWEA, Constellation, EPSA, MidAmerican, PPL, and Renewable 

Energy. 

281 E.g., APPA Reply Comments, Powerex, and Salt River. 
Docket Nos. RM05-25-000 and RM05-17-000 - 207 – 

is sufficient ATC.282 If the Commission develops new services, TAPS contends that the 

Commission should build on PacifiCorp’s OATT amendments. Many commenters that 

object to requiring new transmission services recommend that the Commission encourage 

transmission providers to develop and adopt new services in response to customer 

needs.283 Ameren explains that this process should result in additional services being 

provided that meet the needs of the customers, that are physically feasible considering the 

existing uses of the system, and that do not adversely affect the service provided to other 

users of the system and are not unduly discriminatory. Finally, several commenters 

express a general sentiment against requiring a service that may not be suited to all 

regions or systems.284

296. Commenters also expressed support for services aside from, or in addition to, 

conditional firm service. Exelon proposes that the Commission should require "seasonal 

firm" service, though other commenters ask if seasonal firm service would invite 

hoarding or “cream skimming.” MidAmerican contends that in most cases, the need for 

 282 See PacifiCorp Open Access Transmission Tariff, section 19.7, FERC Electric 

Tariff, Fifth Revised Volume No. 11, Substitute Original Sheet No. 100 (effective 

April 26, 2004); see also PacifiCorp Open Access Transmission Tariff, Schedule 7, 

Long-Term Firm Point-To-Point Transmission Service, section 2, FERC Electric Tariff, 

Fifth Revised Volume No. 11, First Revised Sheet No. 252 (effective April 1, 2006) 

(rates for partial delivery of long-term firm point-to-point transmission service). 

283 E.g., Ameren, Bonneville, Cinergy, EEI, KCP&L, Nevada Companies, 

NRECA, Salt River, Sempra Global, Southern, TVA, and WAPA. 

284 E.g., Ameren, Cinergy, Salt River, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 208 – 

seasonal service can be accommodated by multiple consecutive purchases of monthly 

service. PPL supports a required "partial firm" service that is confirmed and available on 

a firm basis but provided in various amounts over an annual period. PPL states that the 

amount of partial firm service offered would be shaped to match the available capacity 

within each interval or the year. Powerex and WAPA argue long-term priority non-firm 

point-to-point service is the most workable new service. 

297. MidAmerican states that various transmission providers interpret and apply the 

provisions of section 19.7 (Partial Interim Service) of the pro forma OATT in different 

ways. MidAmerican states that the Commission should clarify whether section 19.7 

refers to a partial period of service (i.e., granting firm service for the full MW amount of 

the initial request, but for only a portion of the requested time period), or a partial 

quantity of service (i.e., granting firm service for the time period of the initial request, but 

for only a portion of the requested full MW amount). MidAmerican suggests that the 

revised OATT should provide that partial interim service be offered both for partial 

periods and for partial quantities. 

298. Bonneville states that, currently, when a customer accepts an offer of partial 

service, Bonneville keeps the remaining portion of the customer’s request in the queue if 

the customer executes a system impact study agreement. Bonneville contends that the 

Commission’s OASIS Standards and Communication Protocols, however, appear to 

disallow this result, as does standard OASIS functionality. Bonneville asks that the 
Docket Nos. RM05-25-000 and RM05-17-000 - 209 – 

Commission clarify whether the Commission intends that a customer accepting an offer 

of partial service should lose its position in the queue. 

299. EPSA further argues that transmission providers should be required to 

accommodate a request for any service, whether or not articulated in the new OATT, to 

the extent they can do so, on a nondiscriminatory basis and without unreasonably 

affecting reliability. EPSA also states that the burden should be on the transmission 

provider to state in writing why it cannot accommodate any given request. 

Discussion 

 Proposed Findings

300. The Commission preliminarily finds that the existing methods for evaluating 

requests for long-term firm point-to-point service may no longer be just, reasonable and 

not unduly discriminatory. We believe that transmission providers may evaluate 

transmission availability to serve long-term transmission service requests in a manner 

that is not comparable with the method they use to evaluate transmission needs for 

bundled retail native load and, therefore, that certain reforms are necessary to ensure 

comparability. 

301. When a transmission provider considers new resources to serve its bundled retail 

native load, the transmission provider will not eliminate an otherwise economic option 

because the resource may not be deliverable in a few hours of the year. Rather, the 

transmission provider will evaluate whether it can redispatch its resources as necessary to 

ensure that load is served on a reliable and economic basis. If redispatch is needed in 
Docket Nos. RM05-25-000 and RM05-17-000 - 210 – 

only a few hours of the year, the transmission provider typically will not construct new 

facilities to accommodate new resources. Rather, the transmission provider will look for 

a resource at a different location to fulfill its needs on a least cost basis taking into 

account transmission and energy costs. This use of redispatch to accommodate a new 

resource means that the resulting service is provided even though the transmission 

provider’s power flow studies show that ATC is not available in all hours of the year. In 

this situation, the new resource receives a firm service that is not currently available on 

many systems to OATT customers because the transmission provider uses redispatch on a 

long-term basis to accommodate a new resource for which ATC is not available in every 

hour; in some respects, this firm service is similar to conditional firm service because it 

uses firm transmission capacity to serve bundled retail native load even though the 

resource is not deliverable in every hour of the year. 

302. The Commission believes that the current practices for evaluating long-term 

transmission service requests generally may not reflect the same practices used to 

evaluate transmission needs to serve bundled retail native load. Under current practices, 

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 long-term firm transmission 

service cannot be provided out of existing transmission capacity. Section 19.3 of the pro 

forma OATT provides that a system impact study is required before the transmission 

provider must identify available redispatch options. Before redispatch options are 

offered, however, the customer must also agree to fund a facilities study to determine 
Docket Nos. RM05-25-000 and RM05-17-000 - 211 – 

whether redispatch is less expensive than the transmission facilities upgrades.285 Thus, it 

is only if the customer requests a system impact study and facilities study, and agrees to 

pay for the studies, that the request will be evaluated further and the option of redispatch 

will be offered to the customer. This study process is both time consuming and 

expensive. More importantly, it differs from the evaluation typically undertaken by the 

transmission provider in deciding whether transmission is available to serve bundled 

retail native load with a new resource. 

303. In Order No. 888, the Commission’s goal was to “facilitate the development of 

competitively priced generation supply options, and to ensure that wholesale purchasers 

of electric energy can reach alternative power suppliers and vice versa.”286 The first part 

of this goal, development of competitive supplies, has been realized to some degree.287 

However, the lack of transmission access threatens the viability of customer alternatives 

to their traditional suppliers. Without long-term firm service, it is difficult for alternative 

suppliers to procure the financing they need for project development. Customers taking 

 285 See pro forma OATT section 27. 

286 Order No. 888 at 31,646. 

287 In 2004, electric generation from IPPs represented an increasing share of the 

wholesale markets with nearly 36 percent of total sales, a significant increase from 1996 

when they accounted for only 12 percent of total sales. In 2004, IPPs accounted for 

36 percent of generator nameplate capacity compared to 56.5 percent for utilities and 

7.5 percent for combined heat and power. Office of Coal Nuclear Electric and Alternative 

Fuels, Energy Information Administration, Electric Power Annual 2004 at 9 (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 212 – 

non-firm point-to-point service have a lower reservation priority and are subject to 

curtailment and interruption more frequently than network customers taking transmission 

service from resources other than designated network resources. Thus, the lack of longterm firm transmission access being provided on a nondiscriminatory basis is a 

significant problem in realizing the goals of Order No. 888. 

304. The Commission's preliminary view is that current practices do not adequately 

reflect the manner in which transmission service is planned for bundled retail native load 

and may no longer be just, reasonable and not unduly discriminatory. Transmission 

customers, especially those customers seeking service to or from new generation 

resources, must be given greater flexibility of service to meet their needs comparable 

with the flexibility provided on behalf of bundled retail native load. New generation 

resources often face a grid that cannot accommodate requests for long-term firm 

transmission, at least not without the significant delay required by transmission 

construction, despite the fact that redispatch options may exist that would allow that 

resource to be accommodated. In sum, maintaining the status quo, as advocated by 

several commenters, may be insufficient to ensure comparable treatment of new 

generation resources for all transmission customers, eliminate barriers to entry for new 

generation sources seeking long-term transmission arrangements, and encourage the 

efficient and flexible use of the transmission system in a competitive market. 
Docket Nos. RM05-25-000 and RM05-17-000 - 213 – 

Proposed Solutions

305. The Commission believes there are two basic options for addressing this 

problem.288 The first option focuses on generation redispatch to accommodate long-term 

firm point-to-point service, while the second option creates a modified form of firm 

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's preliminary 

view is that the redispatch option is superior because it: (1) mirrors the way that 

transmission providers plan for bundled retail native load, (2) would provide firm service 

to new entrants, rather than service that is subject to more frequent curtailment in certain 

hours of the year, and (3) may avoid certain implementation issues associated with 

designing a modified long-term point-to-point service. However, we seek comment on 

this preliminary view and on both of the options outlined below. 289

 288 We will continue to encourage transmission providers to propose other services 

requested by customers or such services that may meet their customers’ and systems’ 

needs as energy markets evolve. However, the Commission does not propose to require 

transmission providers to provide any service other than the services expressly set forth 

in the pro forma OATT. In response to EPSA, the decision to provide a new OATT 

service in the first instance remains with the transmission provider. Moreover, several of 

the proposals included in this NOPR such as lifting the price cap associated with capacity 

reassignment for firm point-to-point service and hourly firm point-to-point service should 

provide transmission customers with greater service flexibility. 

289 We also request comment on the applicability of these two options for 

transmission providers who operate RTOs or ISOs. Because RTOs provide redispatch 

service and the ability to access transmission with no prior reservation by paying 

congestion charges, they may not need to reform their existing procedures to satisfy our 

proposal with respect to redispatch. We also note that conditional firm service has the 

(continued) 
Docket Nos. RM05-25-000 and RM05-17-000 - 214 – 

Redispatch Service 

306. The Commission believes that full utilization of generation redispatch is the 

preferred method of ensuring that long-term point-to-point service is not unduly 

discriminatory and does not serve as a deterrent to new entry. The preferred approach is 

described below. 

307. Section 13.5 of the pro forma OATT requires the transmission provider to expand 

or upgrade its transmission system or, if it is more economical, to redispatch its resources 

to provide requested firm point-to-point 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 service; or (2) interfering with the transmission 

provider’s ability to meet prior firm contractual commitments to others. The cost of any 

redispatch performed pursuant to section 13.5 is to be specified in the service agreement 

prior to initiating service and charged to the transmission customer consistent with 

Commission policy. For network service, section 33.2 of the pro forma OATT also 

requires all network customers to agree to redispatch their network resources, along with 

transmission provider’s own resources, to relieve a constraint that may impair reliability. 

Section 33.3 of the pro forma OATT provides that the costs of reliability redispatch 

 

potential to disturb the link between long-term service and the allocation of Financial 

Transmission Rights (FTRs) or auctions of FTR rights. 
Docket Nos. RM05-25-000 and RM05-17-000 - 215 – 

performed pursuant to section 33.2 are to be shared between network customers and the 

transmission provider on a load-ratio share basis.290 

308. To encourage the provision of redispatch as an option to facilitate use of the 

existing transmission grid, we propose to revise the pro forma OATT to require the offer 

of redispatch prior to the performance of a facilities study. We note that the system 

impact study, as defined by the pro forma OATT, is the transmission provider’s 

assessment of the adequacy of its grid to accommodate a request for firm point-to-point 

or network service and whether any additional costs may be incurred to provide the 

requested service. It is followed by a facilities study, which is defined as an engineering 

study to determine the transmission system modifications necessary to provide the 

requested service, including cost and scheduled completion date. Neither study 

references the steps necessary to evaluate the cost of redispatch that could be performed 

in lieu of expanding the grid. Therefore, we propose that the transmission provider must, 

as part of the system impact study process, include an estimate of the number of hours of 

redispatch that may be required to accommodate the request for transmission service, and 

a preliminary estimate of the cost of that redispatch. The customer would then be given 

the option of having the transmission provider perform the necessary studies to determine 

the projected redispatch costs or perform the facilities study, or both. 

309. Consistent with the existing requirements of the OATT, the redispatch 

 290 Order No. 888-A at 30,267. 
Docket Nos. RM05-25-000 and RM05-17-000 - 216 – 

requirement would apply to the redispatch of the transmission provider’s own generation 

resources and would not require the transmission provider to purchase new resources to 

provide this service.291 However, we propose to require the transmission provider, when 

it cannot accommodate a long-term firm point-to-point transmission request through 

redispatch of its own resources, to identify the generators in other control areas that could 

relieve the constraint on the affected flowgates to allow the transmission customer to seek 

redispatch with transmission providers in adjacent control areas to remove such 

constraints. We also seek comment on whether to expand the existing OATT obligation 

to require the transmission provider to redispatch not just its own resources, but those of 

its network customers also, subject to the network customers receiving appropriate 

compensation when their resources are redispatched. 

 291 However, we also request comment on whether it would be appropriate to 

require the transmission provider to contract to purchase generation from outside of its 

control area if it would facilitate a firm transaction. We note that at least one redispatch 

provisions currently in use contemplates the use of third-party generation for redispatch. 

See Deseret Generation and Transmission Cooperative, Inc. (Deseret) FERC Electric 

Tariff, First Revised Volume No. 2 (Deseret OATT), accepted for filing in Deseret 

Generation and Transmission Cooperative, Inc., Docket No. ER01-2642-000 (Aug. 27, 

2001) (unpublished letter order). Attachment J of Deseret’s OATT states, in part: “If 

redispatch services are provided under this Attachment J, the [t]ransmission [p]rovider 

will in good faith attempt to relieve the constraint by the least-cost means, whether by 

seeking a change in generation output from the [t]ransmission [p]rovider’s [m]erchant 

[f]unction or from any other feasible generator or by other means including facilitating 

the payment of firm transmission customers to temporarily give up their rights to relieve 

the constraint.” Deseret OATT, Attachment J, Part I.D, Original Sheet No. 340 (effective 

July 1, 2001). 
Docket Nos. RM05-25-000 and RM05-17-000 - 217 – 

310. Another issue that arises is how the redispatch option should be priced. The pro 

forma OATT caps the cost of redispatch at the cost of constructing the network upgrades 

needed to facilitate the requested transmission service. Some commenters discuss what 

costs should be included in a redispatch rate, such as start-up costs, higher maintenance 

costs and fuel differentials, and state that inclusion of these charges would send clearer 

price signals and induce transmission investments.292 

311. Establishing a formula rate for redispatch costs may be one way to ensure greater 

use of this option, both to facilitate long-term requests for service and to grant customers 

greater flexibility in choosing resources on a daily or hourly basis. A redispatch pricing 

proposal could include a MW quantity, the incremental cost of fuel (increasing the supply 

of fuel) at the point of delivery, and the decremental cost of fuel (decreasing the supply of 

fuel) at the point of receipt capped at the price of fuel. These costs could be calculated 

based 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.293 We invite comments on 

whether including such a formula in the transmission provider’s OATT would facilitate 

redispatch and whether it should account for other, hard-to-quantify costs such as those 

listed by EEI: start-up costs, higher capital costs due to shorter life and accelerated 

replacement, higher maintenance costs, and potential emergency power purchases to 

 292 E.g., Ameren, EEI, Progress Energy, and Southern. 

293 For example, redispatch costs = 75 MW x ($60 incremental cost at the point of 

delivery - $15 decremental cost at the point of receipt) = $3,375. 
Docket Nos. RM05-25-000 and RM05-17-000 - 218 – 

serve load in constrained areas. One option might be to establish a standard per kWh fee 

for such costs, as was initially done for ancillary service costs. 

312. There are few examples of functioning redispatch programs on which to base any 

kind of generic change to the pro forma OATT. However, the Commission has approved 

OATT provisions for SPP294 (prior to its becoming an RTO) and Deseret.295 

313. The redispatch provisions in SPP’s OATT permitted a transmission customer 

facing a constrained path to decide whether to: (1) go forward with its requested 

transmission service, (2) obtain relinquished capacity (solicit from holder of firm 

transmission rights the price at which they would relinquish their rights subject to the 

caps), (3) reduce transmission service to match the level of ATC without redispatch, 

(4) pay for redispatch, or (5) forego the transmission transaction. 

314. Under Attachment H of SPP’s OATT (Redispatch Procedures and Redispatch 

Costs for Short-Term-Firm Point-to-Point Transmission Service Subject to Redispatch 

Cost) the charges to be paid by the transmission customer for redispatch service could not 

exceed the charges the transmission customer would have paid under SPP’s point-topoint tariffs. Stated differently, SPP capped the redispatch charges at a level that ensures 

that total charges did not exceed the total charges the customer would have paid under 

 294 See Southwest Power Pool, Inc., 82 FERC ¶ 61,267, modified, 82 FERC 

¶ 61,285, order on reh’g, 85 FERC ¶ 61,031 (1998); Southwest Power Pool, Inc., 

84 FERC ¶ 61,055 (1998). 

295 See supra note 291. 
Docket Nos. RM05-25-000 and RM05-17-000 - 219 – 

individual company tariffs. For generation resources, the redispatch included the higher 

of incremental or replacement fuel costs and incremental operation and maintenance 

costs of generation facilities necessary to relieve constraints on the transmission system. 

315. The redispatch provisions in Deseret’s OATT are designed to track cost causation 

with redispatch costs and contains features similar to the SPP OATT provisions such as 

providing customers with the opportunity to obtain relinquished capacity. Like SPP, the 

redispatch costs in Deseret’s OATT are capped at the cost incurred by the transmission 

provider to provide the requested service. Under Attachment J of Deseret’s OATT 

(Redispatch Protocol), generally the redispatch costs are calculated by multiplying the 

redispatch quantity, in MWh, that is required to satisfy the transmission customer’s 

schedule in that hour by the redispatch price. Attachment J of Deseret’s OATT also 

includes provisions for crediting and netting of redispatch costs. 

316. We also are concerned that there is a great deal of complexity and fuel price risk in 

projecting years into the future the hours of redispatch that will be required to grant the 

transmission request and the cost of that redispatch in those hours. Moreover, because of 

the need for involvement of the transmission provider’s generation arm to project costs 

associated with redispatch and the need to factor in unpredictable fuel costs, we are 

concerned about the degree of discretion involved in determining redispatch costs. 

Understandably, the transmission provider does not want to bear the price risk associated 

with projected fuel costs, nor does the customer. PacifiCorp, in its comments, describes a 

possible proposal that would calculate redispatch costs monthly and charge the higher of 
Docket Nos. RM05-25-000 and RM05-17-000 - 220 – 

redispatch or the OATT rate each month. We request comment on whether PacifiCorp’s 

proposal may be a way of addressing the complexity and risk associated with determining 
Docket Nos. RM05-25-000 and RM05-17-000 - 221 – 

redispatch costs over a long period and allow greater access to otherwise unused 

transmission capacity on a firm basis. 

317. We ask for comment on whether all or a portion of SPP’s, Deseret’s, or 

PacifiCorp’s proposals should form the basis for a generic redispatch provision that could 

be included in the pro forma OATT, as a means of ensuring that redispatch service is 

available and priced on a just and reasonable basis. 

318. Finally, we recognize that a transmission provider may need to coordinate with 

marketing affiliate or energy affiliate employees to arrange generation redispatch.296 

However, such communication and coordination raise potential problems for the 

transmission provider regarding compliance with the Commission’s Standards of 

Conduct, which require separating transmission function employees from wholesale 

marketing and energy affiliate employees.297 We seek comment on what communication 

and coordination protocols can be established to permit the provision of generation 

redispatch in a manner that is not unduly discriminatory or preferential, and consistent 

with the Standards of Conduct. 

 296 In this discussion, we use the terms “transmission function,” “marketing 

affiliate” and “energy affiliate” as those terms are used in the Standards of Conduct 

regulations. See 18 CFR 358.3 (2005). 

297 See Order No. 2004 at P 85-94. 
Docket Nos. RM05-25-000 and RM05-17-000 - 222 – 

Conditional Firm Service

319. The Commission seeks comment on whether a modified form of long-term pointto-point service would be preferable to the redispatch service described above. This 

conditional firm service option would address the problem of reliability limitations 

during certain peak hours by allowing the transmission provider to provide non-firm 

service to the customer in those hours. We note that at least one transmission provider 

currently provides this service pursuant to amendments to the partial interim service 

provision of its OATT,298 with only modest differences from the service described below. 

320. As an initial matter, in response to requests for clarification of the partial interim 

service in section 19.7 of the pro forma OATT, we will summarize the Commission’s 

precedent on this service. The Commission has clarified that partial interim service has a 

partial duration element, as well as a partial quantity element.299 For example, in Morgan 

 298 See PacifiCorp, 98 FERC ¶ 61,224 at 61,885 (accepting revisions to 

section 19.7), order on reh’g, 99 FERC ¶ 61,259 (2002). 

299 See, e.g., Idaho Power Co. v. Bonneville Power Administration, 96 FERC 

¶ 61,031 at 61,080-81 (2001) (Idaho Power v. Bonneville) (interpreting section 19.7 to 

require Bonneville to offer 277 MW of monthly short-term firm transmission capacity 

interim service to the entity next in the queue with a request of 577 MW); Morgan 

Stanley Capital Group v. Illinois Power Co., 93 FERC ¶ 61,081 at 61,220 (2000) 

(Morgan Stanley) (“Illinois Power should have offered as much transmission capacity as 

it could provide continuously for the duration of the request, i.e., as many MW of 

transmission service as available for the entire one-year period Morgan Stanley 

requested.”); accord Idaho Power Co., 90 FERC ¶ 61,009 at 61,018-19 (2000) (directing 

transmission provider to provide 18 months of partial interim service for a customer 

requesting eight years of service). 
Docket Nos. RM05-25-000 and RM05-17-000 - 223 – 

Stanley, the Commission found that had the customer requested long-term service for a 

two-year period, but only one year was available, the transmission provider would have 

been obligated to offer service for that one available year.300 The Commission was clear, 

however, that partial interim service does not require the transmission provider to treat a 

request for annual service as if it necessarily included a request for all subsumed monthly 

or weekly durations of service during the requested year.301 In other words, a 

transmission provider does not need to respond to a request for one year of service with 

an offer of monthly service. The Commission has also interpreted section 19.7 to apply 

to requests for transmission service that have not undergone or do not necessarily require 

a system impact study or facilities study.302 Further, the Commission has required 

transmission providers to offer partial interim service even where third-parties must 

 300 Morgan Stanley at 61,220. In response to Bonneville, the Commission clarifies 

that a customer does not lose its queue position for its original request when it accepts a 

counteroffer for less service than originally requested. 

301 Id. at 61,220; Tenaska Power Services Co. v. Southwest Power Pool, Inc., 

93 FERC ¶ 61,082 at 61,222-23 (2000) (both concluding that transmission provider has 

no obligation to respond to a long-term request with an offer of short-term service). 

302 See, e.g., Idaho Power v. Bonneville at 61,080-81 (requiring an offer of partial 

interim service for short-term firm service where a system impact study is not 

applicable); Morgan Stanley Capital Group v. Illinois Power Co., 83 FERC ¶ 61,204 at 

61,912 (ordering partial interim service without requiring a system impact study or 

facility study), clarification granted, 83 FERC ¶ 61,299 (1998), reh’g granted in part, 

93 FERC ¶ 61,081 (2000). 
Docket Nos. RM05-25-000 and RM05-17-000 - 224 – 

provide upgrades in order to provide for the full transmission service request.303 

Although partial interim service has a duration component, it differs from conditional 

firm service, which would require the transmission provider to treat the request for 

service as if it included a request for monthly, weekly, daily, and hourly firm service 

during the year. 

321. If we decline to adopt the redispatch proposal above, any conditional firm service 

that we would order would be made available only to customers who request long-term 

firm point-to-point service. When the long-term firm point-to-point service is not 

available, and the customer requests conditional firm service, the transmission provider 

would evaluate transmission availability for the portion of the long-term request that 

cannot be filled due to lack of ATC. The evaluation of conditional firm availability 

should occur prior to a system impact study or facilities study. In offering conditional 

firm service, the transmission provider must identify the number of hours during the year 

in which the conditional firm customer will have service identical to any other firm pointto-point service, and specify the maximum number of hours of the year during which 

firm transmission service may be unavailable. The conditional firm service agreement 

would identify the conditional curtailment hours, i.e., the number of potential hours 

 303 Bonneville Power Administration, 110 FERC ¶ 61,001 at P 36-37 (directing 

Bonneville to offer to provide customer with whatever portion of the request it could 

provide on a firm basis after the customer’s generation project was energized without 

upgrades to PacifiCorp's system and to amend the agreement after upgrades are 

completed to provide for the full amount), reh'g denied, 110 FERC ¶ 61,094 (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 225 – 

during those conditional times when the customer could have its reservations cut or 

reduced prior to any firm customer reductions. Conditional firm service would include 

an annual cap to the conditional curtailment hours and we seek comment on whether it 

should also include monthly caps for each conditional month. Capacity commitments for 

conditional firm service would be accounted for in the ATC calculations prior to new 

sales of short-term firm transmission service, thus not degrading the value of the 

conditional firm transmission product. 

322. We propose that conditional firm service would be curtailed before firm uses until 

such time as curtailment of the conditional firm service has reached the annual or 

monthly caps, after which time the service would be treated as firm. We propose that 

conditional firm service, during conditional curtailment hours, be treated equivalent to 

secondary network service.304 We decline to adopt the proposed quasi-firm curtailment 

priority because it would require creation of a new curtailment classification including a 

determination concerning the appropriate type of curtailment, i.e., choosing between pro 

rata curtailment currently used for firm transactions or full transaction curtailment 

currently used for non-firm transactions. Institution of a new curtailment class would 

require changes to curtailment protocols and reliability coordinators’ procedures, which 

 304 Secondary network service (section 28.4 of the pro forma OATT) refers to 

transmission service for network customers from resources other than designated network 

resources provided on an as-available basis. Section 14.7 of the pro forma OATT 

provides that secondary network service is curtailed or interrupted before firm network or 

point-to-point service but after non-firm point-to-point service. 
Docket Nos. RM05-25-000 and RM05-17-000 - 226 – 

is potentially burdensome and costly. Further, as discussed below, we believe that 

conditional firm point-to-point service, as proposed, is analogous to the secondary 

network service currently used by network customers and therefore both services should 

enjoy the same curtailment priority. 

323. We propose that customers pay the long-term firm point-to-point rate for 

conditional firm service and have a right of first refusal when firm service becomes 

available for the hours in which they have agreed to be curtailed. This rate for 

conditional firm service is consistent with the Commission’s pricing policies that 

promote maximization of long-term uses of the grid. Also, this rate makes this service 

more equivalent to secondary network service because network customers using 

secondary network service already have paid for the long-term use of the grid. Further, it 

avoids gaming incentives that a discounted rate could provide. For example, a 

discounted rate might provide incentives for customers to request a year of service where 

they know only three months of service is available. We seek to prevent this type of 

gaming by requiring the payment of a long-term firm rate. In this regard, we also expect 

that the long-term firm point-to-point rate will tend to limit the type and number of 

requests for conditional firm service. Customers will weigh the value of the service, 

including the probability of curtailment, against the cost of paying the full long-term firm 

rate, in deciding whether to queue for conditional firm service where customers earlier in 

the queue are offered, for example, 50, 100 or 150 conditional curtailment hours. 
Docket Nos. RM05-25-000 and RM05-17-000 - 227 – 

324. Further, we propose that customers with conditional firm service would qualify for 

rollover rights provided that they meet the other rollover right conditions proposed 

herein. The service agreement for conditional firm service would specify the number of 

conditional curtailment hours. The transmission provider would not be required to plan 

for service to the conditional firm customer during the conditional curtailment hours. 

We seek comment on the application of rollover rights to the conditional firm service. 

325. The Commission is not convinced that it is necessary to make this service 

available to network customers. Network customers enjoy flexibility that point-to-point 

customers do not, given the ability of network customers to use secondary network 

service to access resources other than designated resources on an as-available basis under 

section 28.4 of the pro forma OATT. For example, if a network customer’s request to 

designate a new network resource was denied due to lack of ATC, the network customer 

could seek secondary network service for the resource and receive service on an asavailable basis. Such service would be curtailed only after all non-firm point-to-point 

uses sharing the same flowgate were curtailed. This is similar to the service that we now 

propose for point-to-point customers in the form of conditional firm service. We 
Docket Nos. RM05-25-000 and RM05-17-000 - 228 – 

therefore tentatively conclude that conditional firm service is not needed by network 

customers, though we seek comment on that preliminary finding.305 

326. We acknowledge that the obligation to provide conditional firm service may 

require the transmission provider to model its transmission system and the uses of its 

system with greater specificity. We recognize that all transmission providers do not use a 

single standard engineering approach to evaluate firm transmission service requests: 

some transmission providers have a single powerflow base case for each year studied; 

some use a single base case powerflow model to represent several future years; and 

others may have several seasonal base case powerflows for the study of future years. 

Transmission providers also use different methods to establish generator dispatch for 

input into the powerflow base case models: some transmission providers use heat-rates 

without fuel prices for determining generator output in future years’ models; some use 

economic unit commitment order; and others use projected fuel prices to establish base 

case powerflow generation output. Some transmission providers use an economic 

dispatch model to determine unit dispatch prior to establishing powerflow base cases. 

Additionally, some transmission providers must take into account environmental 

 305 Network customers pay for long-term use of the system and should maintain 

priority use of the system for secondary network service over those paying for non-firm 

use. However, because conditional firm customers will pay for long-term use, they 

should also maintain, for the conditional curtailment hours, a curtailment priority over 

non-firm uses equal to the curtailment priority for secondary network service. 
Docket Nos. RM05-25-000 and RM05-17-000 - 229 – 

considerations, such as the pricing of emissions allowances, in establishing generator 

output for powerflow base case models. 

327. Regardless of the engineering approach used, in responding to a conditional firm 

request, the transmission provider would need to specify for the requesting customer the 

number of hours of firm service available in the year for each MW of firm service 

requested. This may require that the transmission provider produce and examine 

additional powerflow cases or make other process changes. In order to determine the 

number of hours that the requested firm transmission capacity is unavailable, the 

transmission provider may need to model varying load conditions, generation and 

transmission planned outages, and time-contingent or condition-contingent generation 

dispatches. Generally, the greater the number of conditions studied, the lower the risk to 

the transmission provider of an inaccurate estimate of conditional curtailment hours. We 

recognize that there are limits to the accuracy of any prediction of hours of curtailment, 

no matter how detailed the system study. 

328. There are a number of ways for a transmission provider to determine the number 

of hours in a year when firm service is unavailable, i.e., the conditional curtailment hours. 

One method involves scaling down the powerflow base case. Using this method, the 

transmission provider could scale down the load and generation in the base case until the 

entire conditional firm request is available on the studied flowgate. For example, a base 

case might need to be scaled down to 95 percent of the summer peak demand in order to 

accommodate the conditional firm request as firm point-to-point service. The 
Docket Nos. RM05-25-000 and RM05-17-000 - 230 – 

transmission provider would then calculate the number of hours the seasonal load is 

forecast to be 95 percent or higher to come up with the number of seasonal hours of 

curtailment for the conditional firm customer. 

329. Another method involves an inventory of generation and demand shift factors. 

Using this method, the transmission provider could determine conditional curtailment 

hours by adding up all the outstanding generation and load shift factors on the relevant 

flowgate. Once the transmission provider determines the load shift factor on the 

flowgate, it can calculate the reduction needed in regional demand to accommodate the 

conditional firm request by comparing the impact of the request on the power flows. The 

demand reduction would not necessarily correspond perfectly with the requested amount 

of service. For instance, a 200 MW reduction might be required to accommodate a 

100 MW conditional firm request. Once the transmission provider determines a reduced 

load level that would accommodate the conditional firm request, the transmission 

provider would examine load forecasts to calculate the number of hours the load is 

expected to exceed this reduced load level. This alternative method of calculating 

conditional curtailment hours might be more burdensome than scaling down the 

powerflow base case because it requires additional data collection and analysis. 

330. Both of these methods rely on average system conditions and do not take into 

account extreme weather years or unexpected outages. Thus, the methods would provide 

an optimistic view of bulk power facility availability. These methods can be used to 

determine the portion of time (hours) that transmission capability will most likely be 
Docket Nos. RM05-25-000 and RM05-17-000 - 231 – 

available and give general information on when (seasons, months) firm service is 

available. 

331. We seek comment on the most appropriate method of modeling the transmission 

system to determine the number of conditional curtailment hours. We also recognize that 

additional studies may cause additional costs. We seek comment on methods of ensuring 

recovery of these additional costs. 

332. We also acknowledge that provision of conditional firm service may require some 

modification to current transaction tracking procedures in use by the industry and require 

development of additional mechanisms. Today, transmission providers track transactions 

with curtailment priorities so that when congestion occurs transactions are curtailed 

consistent with OATT requirements, i.e., non-firm uses are cut before firm uses and 

short-term transactions are cut before longer-term transactions. In order to implement the 

conditional firm service, transmission providers would need to determine in advance of 

scheduling deadlines whether the service should be tracked as a long-term firm use or to 

reflect the use of the conditional curtailment hours.306 If the service is treated as firm 

during a certain period, the transaction would not be cut before other firm uses. The 

transmission provider would have to perform a calculus, taking into account forecast load 

and transmission and generation availability, to determine the need to cut the conditional 

 306 We propose that during conditional curtailment hours, the transaction would be 

tagged with the network non-firm tag (currently used for secondary network service). 
Docket Nos. RM05-25-000 and RM05-17-000 - 232 – 

firm transaction in the next period prior to scheduling the transaction as conditional firm. 

While we do not view this as an insurmountable problem, we note that the decision to 

curtail a conditional firm transaction prior to other firm uses simply cannot be made in 

real time. We also note that the transmission provider would need to develop a 

mechanism to track the number of annual conditional curtailment hours in each service 

agreement and its annual or monthly use of those hours. Such a tracking mechanism 

would ensure that the transmission provider did not exceed the annual or monthly cap on 

conditional curtailment hours in any particular service agreement. 

2. Hourly Firm Service

333. The pro forma OATT contains a one-day minimum term for firm point-to-point 

service. In Order No. 888, the Commission chose a one-day minimum over a one-hour 

minimum because of concerns expressed by commenters.307 There, commenters argued 

that comparability would not be achieved if some point-to-point customers were 

permitted to take service for one hour and receive the same priority as native load and 

other long-term customers that have to pay the fixed cost of the transmission system 

every hour of the year. They also expressed concern that a one-hour minimum term for 

firm point-to-point service (hourly firm) would promote selective use of the transmission 

system, impair the ability of a utility to plan its system, and adversely affect longer term 

transactions. Finally, some expressed concern that a one-hour firm service may 

 307 Order No. 888 at 31,752. 
Docket Nos. RM05-25-000 and RM05-17-000 - 233 – 
Docket Nos. RM05-25-000 and RM05-17-000 - 234 – 

encourage speculative requests for service during the system peak day (a practice known 

as "cream skimming"). 

334. In the NOI, the Commission noted that several public utility transmission 

providers have individually filed for and received Commission authorization to modify 

their OATTs to provide hourly firm point-to-point service.308 In the NOI, the 

Commission sought comment on whether the concerns expressed in Order No. 888 

remain valid, and whether hourly firm service should now be required. The Commission 

also asked whether hourly firm requests should be batched to allow the transmission 

provider to evaluate them as if they were a single request, and whether scheduling 

timelines for firm and non-firm hourly transmission service should differ. 

 Comments

335. Some commenters support requiring transmission providers to adopt hourly firm 

service.309 Alberta Intervenors and TransAlta argue that hourly firm service encourages 

trade and market liquidity. Regarding the concerns cited in Order No. 888, EPSA argues 

that, as a practical matter, daily firm service already receives an equal priority to native 

load and other long-term customers, and none of the concerns expressed in Order No. 888 

 308 The NOI cited Entergy Services, Inc., 85 FERC ¶ 61,163 (1998), order on 

reh’g, 91 FERC ¶ 61,153 (2000) and El Paso Electric Co., Docket No. ER04-567-000 

(Apr. 9, 2004) (unpublished letter order). 

309 E.g., Alberta Intervenors, Alcoa, Calpine, Constellation, EPSA, HQ Energy, 

PPL, and TransAlta. 
Docket Nos. RM05-25-000 and RM05-17-000 - 235 – 

have materialized. “Cream skimming” should not be a problem, EPSA continues, 

because firm transmission reservations are not cost-free, and transmission customers are 

unlikely to commit financial resources for speculative purposes. Constellation argues 

that there should be no concern that comparability will be eroded because hourly firm 

service provides additional flexibility to the competitive markets. PPL argues that in 

non-ISO/RTO regions like the western United States, hourly firm service could help to 

maximize the use of existing transmission facilities, increase efficiencies in wholesale 

markets, and allow customers to purchase only the amount of firm transmission service 

that they need. 

336. Some commenters offer qualified support for hourly firm service.310 For example, 

South Carolina E&G states that before the Commission requires hourly firm service, it 

should obtain empirical market information on transmission providers’ ability to provide 

such service. In its reply comments, Powerex explains that there is a potential for a 

detrimental effect if a transmission provider is not able to accurately determine its ATC, 

and before making hourly firm service mandatory, the Commission should ensure that the 

rights of long-term firm customers will not be negatively affected. 

 310 E.g., APPA, Northwestern, Powerex, Public Power Council, Salt River, and 

South Carolina E&G. 
Docket Nos. RM05-25-000 and RM05-17-000 - 236 – 

337. Among commenters who oppose requiring the adoption of hourly firm service,311

many repeat arguments that appeared in Order No. 888. For example, several 

commenters express concern that hourly firm service will lead to “cream skimming,” 

result in unfairness to longer-term firm transmission customers who would have to be 

curtailed pro rata along with customers who have only made hourly firm commitments, 

or create inefficiencies by having a higher reservation priority than subsequently 

submitted load-based services such as secondary network service.312 But other 

commenters who oppose requiring hourly firm service state that the concerns expressed 

in Order No. 888 may no longer be a major problem, and may be addressed by allowing 

hourly firm service to be pre-empted by longer term firm service requests.313

338. TVA argues that reservations for hourly firm service would nearly always end up 

being bumped by requests for longer service and as such would waste valuable time and 

increase administrative costs with no real benefit. 

Processing

339. On the issue of whether a transmission customer should be permitted to batch 

requests for service, those in favor generally state that batching allows for greater 

 311 E.g., Ameren, APS, Duke, EEI, KCP&L, LG&E, LPPC, MidAmerican, 

NRECA, Progress Energy, Snohomish, Southern, TAPS, TVA, TDU Systems, and 

WAPA. 

312 E.g., LG&E, Progress Energy, Southern, and TAPS. 

313 E.g., EEI and WAPA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 237 – 

efficiencies.314 For example, Bonneville states that batching in the hourly market would 

decrease the response time for all requests in the hourly queue. Salt River states that a 

potential customer should be able to submit a batch of requests (e.g., a block of hours) 

that is useful in shaping the service to its load-serving needs. Snohomish states that in 

the day-ahead schedule submittals, batching of hourly firm transmission requests for 

evaluation as a single request should be permitted, but for periods prior to day-ahead, 

batching of hourly requests should not be allowed due to the potential for “cream 

skimming.” 

340. Among those opposed to or expressing reservations regarding batching, Ameren 

and EEI argue that transmission providers already have the ability to process multiple 

requests from the same party, but they caution that batching requests for simultaneous 

modeling purposes (e.g., transmission from points A to B and B to A simultaneously) 

would be difficult to implement. WAPA states that, in its experience, the majority of 

hourly firm transmission requests must be uniquely identified and evaluated for potential 

conflicts with longer-term firm transmission requests. 

Scheduling

341. The pro forma OATT currently requires that schedules for firm and non-firm 

service be submitted on different timelines. Schedules for hourly non-firm point-to-point 

 314 E.g., Alberta Intervenors, Bonneville, Constellation, EPSA, and South Carolina 

E&G. 
Docket Nos. RM05-25-000 and RM05-17-000 - 238 – 

service must be submitted to the transmission provider no later than 2:00 p.m. the day 

before service is to commence.315 For all firm services, schedules must be submitted to 

the transmission provider no later than 10:00 a.m. the day before service is to 

commence.316 

342. Some commenters argue that firm and non-firm hourly services should be subject 

to the same scheduling timeline.317 To do otherwise, Snohomish argues, would be 

administratively burdensome and without benefit to the transmission provider or 

transmission customer. Those arguing for different scheduling timelines generally argue 

that the scheduling time-frames for firm and non-firm transmission service should remain 

different, at least on a pre-schedule or day-ahead basis, because the transmission provider 

must know the full extent of firm utilization before non-firm offerings can be 

determined.318 

Discussion

343. The Commission proposes to add point-to-point hourly firm service to the pro 

forma OATT because it will eliminate a barrier to the development of markets and 

 315 See pro forma OATT section 14.6 (also allowing schedules to be submitted by 

a reasonable time that is generally accepted in the region). 

316 See pro forma OATT section 13.8 (also allowing schedules to be submitted by 

a reasonable time that is generally accepted in the region). 

317 E.g., Ameren, Constellation, PNM-TNMP, Powerex, Salt River, Snohomish, 

and South Carolina E&G. 

318 E.g., Ameren, Northwestern, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 239 – 

thereby decrease opportunities for undue discrimination. The terms of service we 

propose will ensure that hourly firm customers are offered service in a manner consistent 

with comparability principles, and pay their fair share of system costs. We conclude that 

hoarding and speculation should not be a major concern because requests for hourly firm 

service are subject to preemption by longer-term requests for service. We also conclude 

that the provision of hourly firm should have no effect on investment in the grid because 

a transmission provider does not plan its system to meet hourly firm, or any other shortterm firm, transmission requests. In addition, the expected effect of hourly firm on longterm transactions is no different than the effect of other short-term firm services. For 

example, though commenters are correct that hourly firm will be curtailed pro rata with 

longer term firm point-to-point service, this is already true of daily firm point-to-point 

service. As noted in the NOI, many transmission providers already offer this service and 

there appear to be no technical impediments to offering it, nor have customers on these 

systems expressed any concern about the effect of hourly firm on long-term firm services 

or curtailments. Therefore, we conclude that the concerns expressed in Order No. 888 

regarding unduly discriminatory effects of hourly firm service have proven unfounded, 

and we propose that hourly firm service be a required offering in the pro forma OATT. 

344. As for the pricing of hourly firm service, consistent with Commission precedent, 

we propose to use the "IES Method" and apply different pricing for hourly firm service 
Docket Nos. RM05-25-000 and RM05-17-000 - 240 – 

based on whether the service is taken during peak or off-peak hours.319 Pricing for 

hourly firm service during peak periods would be based on 4,160 hours annually of peak 

usage over 52, 5-day weeks of 16-hour days (52 x 5 x 16 = 4,160), rather than all 8760 

hours of the year. In other words, the rate is derived from the hours during which the 

facilities are likely to be used, rather than the total hours in the year. It is premised on the 

assumption that a customer using the transmission system for the 16 peak hours of the 

day should pay the same contribution to fixed costs as a customer who has reserved 

capacity on a daily basis.320 But because hourly service is unlikely to be taken only 

during peak hours, we propose to allow pricing for hourly firm service for off-peak hours 

based on 8,760 hours 

 319 The method is named for a proceeding in which peak and off-peak pricing was 

applied to hourly non-firm transmission service. 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, 1999 U.S. App. LEXIS 3998 (Feb. 23, 1999) 

(unpublished opinion); see 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). 

320 Peak period pricing is referred to as the “Appalachian Method” or "AEP 

Method," and takes its name from the proceeding in which it originated. Appalachian 

Power Co., 39 FERC ¶ 61,296 (1987). The Appalachian Method is consistent with the 

premise that firm transmission service be priced based on the system's peak periods of 

usage. See Entergy Services, Inc. 85 FERC ¶ 61,163, at 61,645 (1998) (approving 

application of the method for firm service on an hourly basis during peak hours), reh'g 

denied, 91 FERC ¶ 61,153 (2000). 
Docket Nos. RM05-25-000 and RM05-17-000 - 241 – 

of usage.321 This is appropriate because customers using short-term service during offpeak hours do not constrict the system during the peak period, and should pay less than 

what they pay during the peak period.322 To ensure that hourly customers do not pay 

more than their fair share of fixed costs, consistent with the pricing principles set forth in 

Order No. 888, the total charge in any day for hourly service cannot exceed the stated 

daily rate multiplied by the maximum hourly capacity reservation during such day.323 

We conclude that using the IES Method to price hourly firm service at a higher rate 

during peak periods will ensure that hourly firm customers pay a fair share of the costs of 

the transmission system and, as a result, mitigate “cream-skimming” concerns. 

345. As for allowing transmission customers to batch requests for service, we conclude 

that allowing such batching creates administrative efficiencies for the transmission 

customer and transmission provider alike. Therefore, we propose allowing transmission 

 321 See IES Utilities, Inc., 81 FERC at 61,833-34 (approving use of an 8,760 hour 

year to calculate rates for non-firm service on an hourly basis during off-peak hours); 

Entergy Services, Inc., 85 FERC at 61,645 (approving use of an 8,760 hour year to 

calculate rates for firm service on an hourly basis during off-peak hours). 

322 Appalachian Power Co., 39 FERC at 61,965; see American Electric Power 

Service Corp., 88 FERC ¶ 61,141 at 61,453-54 (1999). 

323 And, in turn, the total demand charge in any week pursuant to a reservation for 

hourly or daily service cannot exceed the weekly rate multiplied by the maximum hourly 

capacity reservation in any hour during such week. See pro forma OATT schedules 7 

and 8; see also Entergy Services, Inc., 85 FERC ¶ 61,163 at 61,645 (1998) (applying 

these principles to a proposal for firm service on an hourly basis), reh'g denied, 91 FERC 

¶ 61,153 (2000). 
Docket Nos. RM05-25-000 and RM05-17-000 - 242 – 

customers to batch requests and schedules for hourly firm service that will be provided 

within the same day. 

346. The Commission also concludes that the current scheduling practices can 

accommodate the scheduling of hourly firm transmission service. To require that both 

firm and non-firm hourly services be scheduled at the same time would require that the 

existing procedures be revised, with no discernible benefit to the transmission customer 

or transmission provider. Even with the addition of this new service, it remains 

reasonable to require that the transmission provider have all firm schedules at the same 

time, and in advance of the deadline for non-firm schedules. Therefore, we propose that 

schedules for firm hourly service, like all other firm schedules, will be due by 10 am the 

day before the service is to commence. 

347. Finally, we propose that, consistent with other durations of service, the 

confirmation period for hourly firm service specified in section 13.2 of the pro forma

OATT will allow longer-term requests for service to preempt shorter hourly firm requests 

for service until one hour before the commencement of hourly firm service. 

3. Rollover Rights

348. Section 2.2 of the pro forma OATT allows existing firm transmission service 

customers -- wholesale requirements and transmission-only customers with contracts of 

one year or more -- the right to continue to take transmission service from the 

transmission provider when the customer’s contract expires, rolls over or is renewed. 

The pro forma OATT provides that the transmission reservation priority is independent of 
Docket Nos. RM05-25-000 and RM05-17-000 - 243 – 

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 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. 

349. 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.324 The Commission also provided that a transmission provider may 

reserve existing capacity for retail native load and network load growth reasonably 

forecasted within the transmission provider’s current planning horizon, but that any 

capacity so reserved must be posted on the transmission provider’s OASIS and made 

available to others until the capacity is needed for the anticipated network or retail native 

load use.325 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 

 324 Order No. 888 at 31,665 n.176. 

325 Id. at 31,694. 
Docket Nos. RM05-25-000 and RM05-17-000 - 244 – 

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.326 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 determine whether or not to build additional facilities to accommodate new 

transmission customers.327 A transmission provider is obligated to curtail service 

pursuant to its OATT or expand its system when its system becomes constrained such 

that it cannot satisfy existing transmission customers, including the exercise of their 

rollover rights, because it should have planned and operated its system with the 

 326 E.g., Southwest Power Pool, Inc., 109 FERC ¶ 61,041 at P 6 (2004). 

327 Id. at P 9. 
Docket Nos. RM05-25-000 and RM05-17-000 - 245 – 

expectation that each long-term firm transmission customer will exercise its rollover 

rights.328 

350. 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.329 

The NOI

351. In the NOI, the Commission sought comment on whether transmission providers 

have hindered transmission customers under pre-Order No. 888 agreements from rolling 

over their contracts that allow purchase of capacity and energy from another supplier. 

The Commission also asked whether the language in section 2.2 of the pro forma OATT 

needs to be reformed to ensure that rollover rights are provided when transmission 

customers are seeking access to alternative supply sources, or whether the issue was an 

enforcement matter. The Commission sought comment on whether the rollover right 

policy determinations made subsequent to Order No. 888 should be included in the pro 

 328 Id.

329 Idaho Power Co. v. FERC, 312 F.3d 454, 462 (D.C. Cir. 2002). 
Docket Nos. RM05-25-000 and RM05-17-000 - 246 – 

forma OATT. The Commission inquired whether there were other problems with 

section 2.2, either as written or as implemented by transmission providers, that need to be 

addressed. The Commission also asked whether potential transmission customers are 

denied transmission access by the exercise of rollover rights. Finally, the Commission 

asked whether it should reconsider the concept of rollover rights and whether the oneyear service with rollover rights is consistent with the need to create incentives for 

transmission investment or should a longer minimum term of service be adopted to 

qualify for rollover rights.330

Comments

352. Many transmission providers and APPA argue that, because a transmission 

provider may not know until 60 days prior to termination whether a contract would be 

renewed, rollover rights in contracts as short as one year inhibit the ability of 

transmission providers to plan their systems.331 Transmission providers also argue that 

the right of first refusal results in the denial of transmission that leads to an inefficient use 

of transmission capacity.332 They explain that the transmission provider must hold back 

capacity from the market for existing transmission customers that have a right of first 

 330 NOI at P 18. 

331 E.g., APPA, Bonneville, Duke, LPPC, Nevada Companies, Progress, and Salt 

River. 

332 E.g., Ameren, Duke, EEI, North Carolina Commission, Santa Clara, and South 

Carolina E&G. 
Docket Nos. RM05-25-000 and RM05-17-000 - 247 – 

refusal but that have not yet indicated whether they intend to exercise it. By the time the 

termination notice is given, other transmission customers that may have wanted to 

reserve the newly freed capacity have been turned away and have made other 

arrangements. They assert that the result is an inefficient use of capacity. In addition, 

these transmission providers argue that the 60-day notice provision does not allow them 

adequate time to re-market any capacity when it is freed-up by the terminating customer.

Further, certain transmission providers argue that the right of first refusal unfairly gives 

transmission customers a valuable “free call option” on transmission capacity without 

any obligation to take the capacity at the end of the contract or to compensate the 

transmission provider for the value of the option.333 To avoid these problems, many 

transmission providers suggest that the rollover right should apply to firm transmission 

contracts with minimum terms of between two and ten years.334 In addition, these 

commenters suggest that, if the Commission lengthens the term of the firm contracts 

eligible for the right of first refusal, the 60-day renewal provision also should be 

extended. 

353. Certain transmission customers argue that the Commission should retain the right 

of first refusal in its present form, or change it only after the Commission requires 

 333 E.g., Ameren, Entergy, and Nevada Companies. 

334 E.g., APPA, Bonneville, Cinergy, LDWP, MidAmerican, Nevada Companies, 

Progress, Santee Cooper, South Carolina E&G, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 248 – 

regional planning or other events occur.335 Transmission customers stress the need for 

the rollover rule as a means to ensure long-term service. According to Constellation, 

transmission customers subject to rollover rights are not temporary customers but are 

long-term customers that happen to take their service under year-to-year agreements.

Likewise, EPSA asserts that rollover rights are important in planning for the long-term 

needs of loads and generation located on the grid and that “the ability to roll over a firm 

transportation contract (by matching the contract term and the rate of competing shippers) 

is the only way that market participants can ensure that their needs will be met.” 

354. Numerous commenters address the impact of native load growth on the right of 

first refusal rule. As previously indicated, the Commission permits transmission 

providers to restrict a firm transmission customer’s right of first refusal based on the 

transmission provider’s reasonable projections of native load growth. Several 

commenters argue, however, that the Commission has not provided adequate guidance as 

to the information a transmission provider must submit to demonstrate native load 

growth.336 Further, commenters argue that the Commission should allow transmission 

providers a means to update their native load data to address any load growth that was not 

anticipated at the time of the original contract. In addition, some commenters argue that 

 335 E.g., AMP-Ohio, Calpine, Constellation, and EPSA. 

336 E.g., Duke, EEI, Entergy, Nevada Companies, Progress Energy, Santee Cooper, 

and Salt River. 
Docket Nos. RM05-25-000 and RM05-17-000 - 249 – 

the Commission’s rejection of native load growth projections in prior cases, and the 

provision for pro rata curtailment of service in the event of capacity shortfalls due to the 

exercise of a right of first refusal, fail to respect the native load preference adopted in 

Order No. 888, as well as in section 217 of the FPA as added by section 1233 of EPAct 

2005. They argue that new section 217 of the FPA reverses Commission precedent that 

limits the ability of transmission providers to recall capacity for native load once it is 

subject to a right of first refusal.

Discussion

355. The comments filed in response to the NOI demonstrate a need to retain, but 

revise, the right of first refusal provision in the pro forma OATT. The Commission 

proposes to revise the right of first refusal provision in the pro forma OATT to apply to 

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, the 

Commission proposes that a transmission customer under a rollover agreement must 

provide notice of whether or not it will exercise its right of first refusal no less than one 

year prior to the expiration date of the transmission service agreement. We agree with 

APPA that these changes strike an appropriate balance between providing customers 

meaningful rollover rights and encouraging long-term contracting, new investment and 

long-term planning. Finally, if the existing customer seeks to exercise its rollover right 

and there is insufficient transmission capacity on the system at the end of the contract 

term to accommodate all of the requests for transmission service, the existing customer 
Docket Nos. RM05-25-000 and RM05-17-000 - 250 – 

would have to agree to accept a contract term at least equal to a competing request by any 

new customer or five years, whichever is longer, and to pay the current just and 

reasonable rate, as approved by the Commission, for such service. 

356. The Commission’s proposal is consistent with the transmission customers’ 

comments that the right of first refusal should be designed to ensure long-term service. 

Extending the minimum term of the right of first refusal agreements to five years will 

encourage long-term use of the grid. In addition, the one-year prior notice requirement 

should allow adequate time for transmission providers to re-market unused capacity that 

may result from a transmission customer choosing not to roll over a service agreement. 

The one-year notice provision also should limit the instances when the transmission 

provider must turn away a transmission request only to find out that it could 

accommodate the request after the transmission customer elected not to roll over. These 

changes should result in a more efficient use of the transmission grid. 

357. If we adopt the proposed minimum five year/one year right of first refusal 

provision in the pro forma OATT, we propose to allow this provision to become effective 

upon Commission acceptance of the transmission provider’s coordinated and regional 

planning process set forth in Attachment K of its OATTs. Thus, all new transmission 

service agreements executed after the effective date of Attachment K will be subject to 

the five year/one year right of first refusal rule. The Commission proposes that 

transmission service agreements subject to a right of first refusal entered into prior to the 

effective date of revised section 2.2, unless terminated, will become subject to the five 
Docket Nos. RM05-25-000 and RM05-17-000 - 251 – 

year/one year right of first refusal rule on the first rollover date after the effective date of 

revised section 2.2. 

358. Our existing policy allows the transmission provider to limit a transmission 

customer’s right of first refusal by reserving capacity to accommodate reasonably 

forecasted and verifiable native and network load growth at the time the initial service 

agreement is executed. Many transmission providers argue that this right should be 

extended to allow the transmission provider to limit the right of first refusal each time the 

right of first refusal is exercised, not only at the time the initial service agreement is 

executed. We believe that our proposal to extend the term of the right of first refusal 

from one to five years should address, in many respects, the concern of transmission 

providers that the existing right of first refusal is unfair to native load customers. Under 

this proposal, a right of first refusal will no longer be granted to users of the grid on an 

annual basis, but rather only to those making longer-term commitments to the grid, as do 

native load customers. In addition, while we expect a transmission provider to be 

continually updating its forecast for native load growth and applying this updated 

projection to new requests for service, applying this to contracts at rollover may require 

an additional change to the right of first refusal process. Specifically, the transmission 

provider would have to compete for the capacity rather than reclaim it through its rights 

to reserve capacity for native load growth. We seek comment on whether this change 

would be appropriate. Further, while we have addressed requests to limit the right of first 

refusal on the basis of native load growth on a case-by-case basis, we recognize that this 
Docket Nos. RM05-25-000 and RM05-17-000 - 252 – 

approach has not yet resulted in a clear and transparent method for demonstrating 

forecasted native load growth. Accordingly, we seek 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 right of first refusal customers. 

359. Many transmission providers argue that our current right of first refusal policy is 

inconsistent with the native load protections contained in section 217(b) of the FPA. 

We disagree, but note that the reforms being proposed here should moot this argument. 

We are proposing to extend the minimum term of the right of first refusal to a period 

(five years) that is more consistent with the planning horizons of transmission providers. 

In addition, limiting the right of first refusal to agreements with terms of five years or 

more will ensure that the right of first refusal is used by customers with long-term 

obligations to purchase capacity rather than as a means for customers with shorter-term 

transactions to use capacity for non-load-serving-entity transactions.337 This is consistent 

 337 This is consistent with the approach suggested by TAPS, which argues that the 

current one-year minimum contract term allows significant capacity on constrained 

interfaces to be tied up in relatively short-term deals simply designed to hold the firm 

reservation as a path for non-firm economy purchases and to block competitors’ firm 

access (e.g., inexpensive, one-year “paper capacity” deals). TAPS also argues that any 

restriction on the availability and flexibility of rollover rights be contingent on an 

expansion of the transmission grid so that transmission customers have reasonable access 

to competitive supplies. We agree that expansion of the grid is critical and accordingly 

have proposed to require coordinated transmission planning on both a local and regional 

level to ensure that transmission customers’ needs are treated comparably to those of the 

transmission provider. This enhanced transmission planning, combined with other 

(continued) 
Docket Nos. RM05-25-000 and RM05-17-000 - 253 – 

with FPA section 217(b)(4), which states that the Commission shall exercise its authority 

"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." Our proposal also is consistent with FPA section 217(b)(2) because it 

continues to allow the transmission provider to limit the right of first refusal to 

accommodate reasonably forecasted and verifiable native load growth. 

360. Under the proposed rule, transmission providers still will be required to plan their 

systems with the expectation that a transmission customer with a long-term transmission 

agreement subject to a right of first refusal will exercise its rollover right at the end of its 

term. We believe it is important to reiterate the obligation on transmission providers to 

maintain ATC for existing transmission customers with rollover rights and our 

expectation that transmission providers will include all customers with rollover rights in 

their long-term planning.338 We understand that some existing reliability procedures or 

practices may encourage transmission providers to exclude certain transmission service 

contracts from their base-case models, even if those contracts contain a rollover right. 

This is inconsistent with Commission policy and undermines the purpose of the rollover 

right, which is to facilitate system planning and reliability. 

 

reforms proposed in this NOPR (e.g., improvements to the calculation of ATC), should 

mitigate TAPS’s concerns by improving the ability to access competitive supplies. 

338 See, e.g., Southern Company Services, Inc., 104 FERC ¶ 61,140 at P 26-27 

(2003). 
Docket Nos. RM05-25-000 and RM05-17-000 - 254 – 

4. Modification of Receipt or Delivery Points

361. 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 on either a nonfirm 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-topoint 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. 

362. In the NOI, the Commission asked whether transmission customers have 

experienced undue discrimination in attempting to redirect to new receipt and delivery 

points pursuant to section 22.2 and whether any reforms were needed. The Commission 

did not specifically ask about section 22.1, but some commenters nevertheless addressed 
Docket Nos. RM05-25-000 and RM05-17-000 - 255 – 

this section. Most commenters, however, did not distinguish whether they were 

concerned with firm or non-firm redirects and instead addressed redirects generally. 

Comments 

363. APPA notes that many of its members have experienced difficulties in changing 

receipt points, especially when such requests involve new sources of supply. In many 

cases, APPA asserts that transmission providers require major upgrades before they will 

grant a redirect to new points. The Public Power Council points out that redirecting to 

new points depends on ATC, and, therefore, the ability to make changes would be 

improved by better public knowledge of ATC at those points in all timeframes and by 

more information about ATC calculation methodologies. EPSA asserts that difficulty in 

redirecting to new points inhibits the ability to reassign capacity. Williams complains 

about delays by transmission providers in answering requests for redirects and urges the 

Commission to enforce OATT procedures and to consider a “fast-track” process for 

reviewing requests to redirect. 

364. Bonneville and EEI believe that any discrimination may be an unintentional result 

of a lack of clarity in the pro forma OATT, and are joined by MidAmerican, Progress 

Energy, and PNM-TNMP in calling for a number of clarifications. MidAmerican 

believes that these clarifications will provide flexibility to transmission customers and 

will enhance the ability to reassign transmission service to customers desiring different 

points of receipt or delivery. 

365. Southern and Ameren assert that because customers often make redirect requests 
Docket Nos. RM05-25-000 and RM05-17-000 - 256 – 

at the last minute, there is often not enough time for the market to respond to capacity 

made available on an abandoned path. Southern also highlights the administrative 

burdens and complexity (particularly for reliability) of processing short-term changes in 

service and suggests that the Commission consider measures to encourage transmission 

customers to provide greater certainty as to the expected paths along which they will 

schedule service and to do so in a more timely manner. Southern, along with Bonneville, 

also urges the Commission to clarify rollover rights when service is redirected to new 
Docket Nos. RM05-25-000 and RM05-17-000 - 257 – 

points. In general, however, Southern believes that the Commission’s current redirect 

policies are reasonable and practical. 

366. A number of commenters focus on other related transmission issues, such as the 

flexibility afforded network service versus point-to-point service or other networkservice-related issues;339 the lack of flexibility with point-to-point service generally;340 

or issues associated with the interconnection of network load at new delivery points.341 

Discussion

367. The Commission believes that it has already addressed many of the concerns 

raised by commenters with regard to reform of section 22 of the pro forma OATT in 

Docket No. RM05-5-000.342 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).343 Order No. 676 incorporates the 

aforementioned standards by reference into the Commission’s regulations; requires 

 339 E.g., Alberta Intervenors, Calpine, and TAPS. 

340 E.g., Occidental. 

341 E.g., NRECA and TDU Systems. 

342 Standards for Business Practices and Communication Protocols for Public 

Utilities, Order No. 676, 71 FR 26199 (May 4, 2006), FERC Stats. & Regs. ¶ 31,216 

(2006). 

343 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 id. at P 3-4. 
Docket Nos. RM05-25-000 and RM05-17-000 - 258 – 

public utilities to implement the standards by July 1, 2006; and requires public utilities to 

file revisions to their OATTs to include these standards.344 The WEQ Standards recently 

adopted by the Commission include a number of standards addressing requirements for 

dealing with redirects on both a firm and non-firm basis.345 In fact, all of the WEQ 

Standards dealing with redirects were adopted by the Commission in Order No. 676, 

except for WEQ Standard 001-9.7, which addresses the impact of a firm redirect on a 

long-term firm transmission customer’s rollover rights under section 2.2 of the pro forma

OATT. The Commission directed the WEQ to reconsider WEQ Standard 001-9.7 and to 

adopt a revised standard consistent with the Commission’s policies.346 The Commission 

also offered guidance to assist the WEQ in developing a standard that is consistent with 

Commission policy.347

368. As noted above, we believe that a number of concerns raised by commenters are 

addressed by the WEQ Standards. For example, we believe that the request of 

commenters for clarification that redirect service may be requested for only a portion of 

 344 The standards will hereinafter be referred to as the WEQ Standards. The 

Commission proposes to add 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. 

345 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.

346 Order No. 676 at P 52. 

347 Id. at P 53-61. 
Docket Nos. RM05-25-000 and RM05-17-000 - 259 – 

the original quantity of service is addressed for firm and non-firm service by WEQ 

Standards 001-9.2 and 001-10.2, respectively, which provide that the transmission 

customer “shall be allowed to request a Redirect on a [Firm/Non-Firm] basis for a portion 

or all of the Capacity Available to Redirect.” Likewise, the request of commenters for 

clarification that it is not necessary for a customer to redirect its service for the entire 

remaining term of service is addressed for firm and non-firm service by WEQ 

Standards 001-9.3 and 001-10.3, respectively, which provide that the transmission 

customer “shall be allowed to request a Redirect on a [Firm/Non-Firm] basis for a portion 

or all of the time period of the Parent Reservation.” While we believe that many 

concerns expressed by commenters with regard to redirects in this proceeding have been 

addressed by Order No. 676, we request that each commenter reconsider its concerns in 

this area with the benefit of Order No. 676’s adoption of the WEQ Standards, and inform 

us if additional concerns remain. The Commission notes that several of the most active 

commenters addressing redirects in this proceeding also were commenters in Docket 

No. RM05-5-000 and therefore should be familiar with whether a particular WEQ 

Standard addresses the issues raised in the comments submitted in this proceeding.348

369. The Commission anticipates that a number of other concerns, while perhaps not 

yet addressed (or addressed fully) by a WEQ Standard, are nevertheless the types of 

 348 For example, Bonneville, EEI, NRECA, and Southern each commented in 

Docket No. RM05-5-000. 
Docket Nos. RM05-25-000 and RM05-17-000 - 260 – 

issues appropriate for the WEQ process. The Commission therefore proposes that each 

commenter that continues to believe additional reform is necessary in this area also 

evaluate whether its concerns would more appropriately be addressed by the WEQ as it 

considers its next version of its standards.349 Specifically, as noted above, the WEQ is 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 requests 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. 

370. The Commission understands, however, that there are also more fundamental 

concerns with regard to section 22 that were raised in the NOI. Many comments reflect 

concerns about the inability of transmission customers to effectively redirect their 

transmission service to new receipt and delivery points in order to accommodate a new 

transaction, the reassignment of capacity, or the designation of a new supply source. 

Generally, these commenters argue 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 at the new points; or 

that the transmission provider takes too long to process its redirect request. Transmission 

 349 The Commission notes 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. RM05-25-000 and RM05-17-000 - 261 – 

providers, on the other hand, complain of the administrative burdens and complexity 

(particularly with regard to reliability) of processing transmission customers’ short-term 

changes in service, and also assert that there is often not enough time for the market to 

respond to capacity made available on customers’ original paths. 

371. The ability to redirect to new points is a function of whether there is ATC at the 

new points. The Commission believes that its proposed reforms requiring coordinated 

transmission planning between transmission providers and their customers, as well as 

regional transmission planning open to all stakeholders, will lead to a more rationally 

planned transmission system that will result in fewer transmission constraints and more 

ATC available to accommodate requests to redirect to new points.350 Additionally, the 

Commission’s proposed reforms regarding the calculation of ATC and increased 

transparency over the process will engender increased confidence among transmission 

customers in their transmission providers’ ATC postings.351 In short, transmission 

customers will have more accurate and complete ATC information to utilize in evaluating 

their redirect options. Moreover, through increased transparency, transmission customers 

will have the information they need to question a transmission provider’s denial of a 

request to redirect. Thus, we believe that our reforms in the area of transmission 

planning and ATC calculation should go a long way toward addressing transmission 

 350 Supra Part V.B. 

351 Supra Part V.A. 
Docket Nos. RM05-25-000 and RM05-17-000 - 262 – 

customer concerns in this area. Should commenters believe that our proposed reforms in 

this area will not address their concerns effectively, or that there is a better way of 

addressing them, we encourage them to submit a specific proposal, along with proposed 

revised pro forma OATT language. 

372. We believe that redirects should be as customer-friendly as possible. Other pro 

forma OATT reforms proposed in this rulemaking should improve the ability to redirect 

transmission service to new points pursuant to section 22. For example, the 

modifications to firm point-to-point service discussed above will be applicable to a 

request to redirect on a firm basis, as such requests are treated as a new request for 

service under pro forma OATT section 22.2. In addition, reforms related to the 

acquisition of service discussed below (e.g., with regard to making and processing 

requests for service, queuing, and reservation priority) should, among other things, help 

to address transmission customer concerns that transmission providers are too slow in 

processing redirect requests. These reforms also should help to address transmission 

provider concerns that customers do not respond completely and in a timely manner and 

that there is insufficient time to re-market capacity on the original paths. 

5. Acquisition of Transmission Service 

a. Processing of Service Requests

373. 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 263 – 

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). Section 19 (Additional Study 

Procedures for Firm Point-to-Point Transmission Service Requests) of the pro forma

OATT provides deadlines that transmission providers must adhere to in issuing system 

impact study agreements and facilities studies agreements and that transmission 

customers must abide by in responding to these study agreements. Section 19 requires 

transmission providers to use due diligence to complete system impact studies and 

facilities studies within 60 days. Section 32 of the pro forma OATT (Additional Study 

Procedures for Network Integration Transmission Service Requests) contains similar due 

diligence deadlines for completing system impact studies and facilities studies associated 

with requests for network service. 

374. In the NOI, the Commission sought comment on problems transmission customers 

and transmission providers have experienced regarding the timely processing of requests 

for transmission service. In particular, the Commission sought comment regarding 

whether transmission customers have experienced delays by transmission providers in 

responding to requests for transmission service in general and, in particular, what 

problems commenters have experienced as transmission providers process the queue for 
Docket Nos. RM05-25-000 and RM05-17-000 - 264 – 

requests for transmission service that cannot be immediately granted due to a lack of 

ATC. We also asked about the type of remedies the Commission should impose on 

public utility transmission providers for missing deadlines set forth in their OATTs. 

Another issue we sought comment on was whether commenters have identified blocking 

issues, such as where a customer submits multiple requests intending to proceed with a 

single request specifically to keep others out of the queue; and if so, whether allowing 

transmission providers to charge a processing fee would reduce the incentive to submit 

multiple self-competing requests. Finally, we sought comment on whether the 

Commission should require transmission providers to study transmission requests as a 

group. 

 Comments

375. A number of merchant generators articulated general concerns regarding the time 

it takes transmission providers to process requests for transmission service.352 EPSA 

notes that timeliness in responding to transmission requests is a consistent problem. 

Constellation states that the untimely processing of requests for transmission service is a 

persistent problem under the OATT, particularly with respect to long-term point-to-point 

service, network service, and modification of network resource designations. Arkansas 

Cities adds that, under the current OATT, utilities’ lenient application of time periods 

needed for the system impact study process and facilities study process cause 

 352 E.g., Constellation, EPSA, Powerex, and Williams. 
Docket Nos. RM05-25-000 and RM05-17-000 - 265 – 

transmission customers to endure significant amounts of time to obtain confirmed firm 

delivery service at a reasonable cost. 

376. A number of commenters suggest that transmission providers should inform the 

Commission when they miss the target deadlines for completing system impact studies 

and facilities studies and/or post performance statistics on their OASIS sites that detail 

the time it takes them to process system impact studies and facilities studies.353 EPSA 

states that it strongly believes that the new OATT should require the transmission 

provider to notify the Commission when it is not able to meet deadlines. TDU Systems 

suggests that one way to address the difficulty of determining acceptable delays is to 

require transmission providers to post statistics on their OASIS sites providing 

information as to the length of time it might take to process requests for transmission 

service. Cinergy proposes that adopting specific reporting metrics that require 

transmission providers to report certain statistics regarding their performance could result 

in an improved quality of service. 

377. A number of merchant generators propose that the Commission assess operational 

penalties on transmission providers that fail to meet the study deadlines detailed in the 

pro forma OATT.354 LG&E recommends that the Commission consistently enforce the 

 353 E.g., Cinergy, Constellation, EPSA, MidAmerican, Powerex, and TDU 

Systems. 

354 E.g., EPSA, Powerex, and Williams. 
Docket Nos. RM05-25-000 and RM05-17-000 - 266 – 

established deadlines through penalties or other remedies unless good cause for failure to 

comply can be shown, so as to promote nondiscriminatory adherence to established 

deadlines. Powerex suggests that the Commission: (a) identify a threshold percentage 

rate of acceptable compliance with response timelines, (b) require transmission providers 

to monitor and post their own rates of compliance with Commission-required timelines 

on a path-specific basis, as well as the reasons for delays, (c) require transmission 

providers whose rate of compliance on a particular path falls below the Commission's 

threshold to file a compliance report with the Commission identifying the problem(s) and 

corrective measures that will be undertaken (including a timeline for implementation of 

the corrective measures), and (d) use a progressive penalty system that begins with 

reporting and auditing requirements for non-compliant transmission providers and then 

moves toward monetary penalties in cases where a transmission provider exhibits a 

pattern of uncorrected noncompliance, as well as in any case where actual bad faith, 

discrimination or preferential treatment has occurred. 

378. A number of transmission providers state that transmission service request 

processing is slowed by excessive requests for transmission service from the same 

transmission customer with essentially the same service attributes (e.g., point of receipt, 

point of delivery, start time, end time, firmness).355 A number of other commenters also 

argue that some transmission customers submit multiple requests for transmission service 

 355 E.g., MidAmerican, Progress Energy, South Carolina E&G, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 267 – 

with no intent to confirm most of the requests if and when the requests are accepted.356 

MidAmerican states that it is aware of cases where customers have submitted multiple 

requests for service associated with a new generator where the location of the new 

generator is not known but queue priority is being sought by the transmission customer. 

MidAmerican adds that the submission of such multiple requests for service affects the 

processing of other lower queued transmission requests. South Carolina E&G states that 

there are instances when a transmission customer submits multiple requests intending to 

proceed with a single request, seemingly with the purpose of keeping others out of the 

queue. AWEA states that transmission queues are frequently jammed with many projects 

holding each other up. AWEA asserts that there often are “zombie” projects blocking the 

queue, without a power purchase agreement or other indication that they are serious 

projects. Suez Energy NA responds that there are blocking issues when a transmission 

customer submits multiple requests for transmission service but intends to proceed with a 

single request. 

379. Several federal power agencies suggest that charging a fee on transmission service 

requests could provide the right incentive to transmission customers to limit requests for 

transmission service to only those requests they expect to confirm.357 Several other 

 356 E.g., Alberta Intervenors, AWEA, Public Power Council, and Suez Energy NA. 

357 E.g., Bonneville and TVA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 268 – 

commenters suggest a similar fee.358 Bonneville supports the imposition of a processing 

fee for multiple requests to provide a disincentive to blocking behavior. Bonneville 

suggests that the fee should provide a disincentive for making multiple, “self-competing” 

requests. Bonneville suggests that, at a minimum, requests with the same point of 

receipt, point of delivery, source, sink, and time-frame should be considered “selfcompeting.” In addition, Bonneville contends that transmission providers should be 

allowed to define parameters to identify additional instances of “self-competing” requests 

on their systems. South Carolina E&G argues that there is merit to the concept of 

charging a processing fee that would increase with the duration of the requested service, 

to reduce the incentive to submit multiple self-competing requests. 

380. The majority of commenters were in favor of allowing, but not requiring, 

transmission providers to study requests for transmission service as a group, also known 

as clustering requests for transmission service.359 APPA and Bonneville suggest 

amending the pro forma OATT so that all requests received during a set time period are 

studied together. EEI argues that the Commission should not require the studying of 

transmission requests as a group, though transmission providers should continue to have 

the discretion to cluster transmission requests when it is efficient to do so. EPSA states 

 358 E.g., Alberta Intervenors, Snohomish, and South Carolina E&G. 

359 E.g., EEI, EPSA, Nevada Companies, PacifiCorp, PNM-TNMP, Powerex, and 

Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 269 – 

that clustering should not be required, but may be considered as a customer option as part 

of a comprehensive planning process. 

381. Bonneville suggests that the Commission adopt two NAESB proposed business 

standards designed to reduce the number of self-competing requests. In particular, 

Bonneville believes the Commission should adopt NAESB’s proposed queue hoarding 

business practice and queue flooding business practice. 

Discussion

382. We agree with commenters who argue that requiring transmission providers to 

report the length of time they take to complete studies pursuant to sections 19 and 32 of 

the pro forma OATT would increase transparency and improve the ability of transmission 

customers and the Commission to detect undue discrimination. Therefore, we propose 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. Transmission providers will be required to post the 

performance metrics, outlined below, for each calendar quarter. Transmission providers 

should begin tracking their performance upon the effective date of the final rule in this 

proceeding 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 should be calculated separately for affiliates’ and non-affiliates’ requests 

for short-term and long-term transmission service. A transmission provider also will be 
Docket Nos. RM05-25-000 and RM05-17-000 - 270 – 

required to post performance metrics for studies that it conducts for RTOs. 

383. We propose to require transmission providers 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. RM05-25-000 and RM05-17-000 - 271 – 

• 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 

384. We also propose 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. We propose to require a transmission provider to 
Docket Nos. RM05-25-000 and RM05-17-000 - 272 – 

file a notice 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. For the purposes of calculating this 

notification trigger, the transmission provider should aggregate all system impact studies 

and facilities studies that it completes during the quarter for non-affiliates.360 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. 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. The 

transmission provider will be deemed to be out of compliance if it completes 10 percent 

or more of non-affiliates’ system impact studies and facilities studies outside of the 

deadlines prescribed in the pro forma OATT. The operational penalty will be assessed on 

a quarterly basis, starting with the quarter following the notification filing and continuing 

until the transmission provider completes at least 90 percent of all studies within 60 days 

after the study agreement has been executed. For any system impact study or facilities 

 360 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. RM05-25-000 and RM05-17-000 - 273 – 

study completed during that quarter and more than 60 days after the study agreement was 

executed, the penalty will equal $500 for each day the transmission provider takes to 

complete the study beyond 60 days. For any system impact study or facilities study that 

is still pending at the end of the quarter and that has been in the study queue for more 

than 60 days, the penalty will equal $500 for each day the study has been in the study 

queue beyond 60 days. Because of their independence, we do not believe that RTOs 

have an incentive to neglect their obligation to process applications for service in a timely 

fashion. As a result, we propose that RTOs will not be subject to this penalty regime. 

385. In addition to the operational penalty described above, we propose to require 

transmission providers to post on their OASIS sites additional performance metrics after 

making a notification filing. Transmission providers will have to post these performance 

metrics until they process at least 90 percent of all system impact and facilities studies 

within 60 days after the study agreement has been executed. Starting the quarter 

following a notification filing, the transmission provider will be required to post: (1) the 

average, across completed system impact studies, of the employee-hours expended per 

completed system impact study; (2) the average, across completed facilities studies, of 

employee-hours expended per completed facilities study, (3) the number of employees 

devoted to processing system impact studies, and (4) the number of employees devoted to 

processing facilities studies. These additional performance metrics should be calculated 

separately for affiliates’ and non-affiliates’ requests for transmission service and for 

short-term and long-term transmission service. 
Docket Nos. RM05-25-000 and RM05-17-000 - 274 – 

386. In addition to the operational penalties described above, we may order other 

remedial actions, consistent with the Enforcement Policy Statement. Any other remedial 

action will be determined on a case-by-case basis. The transmission provider will pay the 

operational penalty described above, consistent with the proposed rule discussed in 

Part V.C.4.b. The transmission provider cannot recover for ratemaking purposes any 

operational penalty it pays for failing to process transmission service studies on a timely 

basis. 

387. With respect to the problem of multiple, self-competing transmission service 

requests, we seek comment on a fee structure that could provide a disincentive for 

transmission customers to submit such duplicative requests without penalizing 

transmission customers that have legitimate requests for transmission service. We seek 

detailed recommendations, including any proposed tariff language, regarding the 

standards we would use to identify requests that would be subject to a fee. We also seek 

recommendations on the level of the fee that balances our 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, we 

seek comment regarding the circumstances, if any, under which the processing fee would 

be refunded to or credited to the transmission customer. 

388. In Order No. 2003, we encouraged transmission providers to study interconnection 
Docket Nos. RM05-25-000 and RM05-17-000 - 275 – 

requests in clusters.361 We likewise encourage transmission providers to study requests 

for transmission service in clusters, though we will not require transmission providers to 

cluster requests for transmission service for study purposes.362 As with interconnection 

requests, studying requests for transmission service in clusters allows the transmission 

provider to consider all requested uses of the transmission system at one time. We seek 

comment regarding whether transmission providers should be required to study requests 

for transmission service in a group if the transmission provider fails to complete studies 

on a timely basis; and, if so, we seek comment on the circumstances that should trigger 

such a requirement and the appropriate method of implementing the requirement. We 

further seek 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. We also seek 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. 

389. In Order No. 676, we incorporated by reference a number of NAESB business 

practices, including the business standards on queue hoarding and queue flooding.363 

 361 Order No. 2003 at P 155. 

362 We note that we previously have allowed transmission providers to study 

requests for transmission service in a group. See, e.g., Southwest Power Pool, Inc., 

110 FERC ¶ 61,028 at P 16 (2005). 

363 See Order No. 676 at P19.
Docket Nos. RM05-25-000 and RM05-17-000 - 276 – 

NAESB’s queue hoarding business practice allows transmission providers to deny a 

transmission customer’s identical requests for transmission service if the customer elects 

not to accept an initial offer of identical, or substantially identical, transmission service. 

NAESB’s queue flooding business practice allows a transmission provider to invalidate 

the submission of additional identical requests for transmission service when the sum of 

all previously submitted identical requests for transmission service equals or exceeds the 

total transfer capability on the requested path for any time period during the duration of 

the requests. We would consider the decision by a transmission provider to deny service 

under the queue hoarding business practice and the decision to invalidate requests under 

the queue flooding business practice to be an act of discretion under 18 CFR § 37.6(g)(4) 

(2005). As a result, the transmission provider is to log the actions it takes under the 

queue flooding and queue hoarding business practices. 

b. Queue Processing Business Practices

390. The set of uniform business practices adopted in Order No. 676 relating to 

transmission service price negotiation and on improving interaction between transmission 

customers and transmission providers over OASIS nodes. These business practices 

include standards for the time limit within which (1) transmission providers must respond 

to requests for transmission service, (2) transmission customers must confirm service, 

and (3) transmission providers must respond to a rebid from a transmission customer.364 

 364 Id., Standards 001-4.6 and 001-4.13. 
Docket Nos. RM05-25-000 and RM05-17-000 - 277 – 

These business practices also include negotiation priority rules, including the terms under 
Docket Nos. RM05-25-000 and RM05-17-000 - 278 – 

which a request can be pre-empted and under which a request has the right-of-firstrefusal.365

391. In the NOI, the Commission sought comment regarding whether there are 

provisions of the pro forma OATT that need to be reformed to better define the 

obligations of public utility transmission providers in responding to requests for 

transmission service. 

 Comments

392. Several commenters asked that the Commission require transmission providers to 

post standard business practices that describe how the transmission provider will process 

requests for transmission service.366 MidAmerican suggests that transmission providers 

should be required to post on their OASIS sites a business practice documenting how 

they process their queues, requests outside the queue, and expected completion times. 

Calpine believes that the processing of requests for transmission service, and the 

deadlines associated with that process, should be standardized for all transmission service 

providers. For example, Calpine notes that Entergy’s OASIS business practices state that 

Entergy will respond to fixed, hourly non-firm transmission service requests “within 30 

minutes of receiving the request for the requests received earlier than 1 hour before the 

service is to commence.” By comparison, Calpine continues, SPP’s tariff explains that 

 365 Id., Standards 001-4.14 and 001-4.16. 

366 E.g., Calpine, MidAmerican, and TDU Systems. 
Docket Nos. RM05-25-000 and RM05-17-000 - 279 – 

hourly, non-firm transmission service requests for the next hour may be submitted no 

later than 20 minutes prior to the start of service. 

Discussion

393. Order No. 676 contains many of the business practices we expect transmission 

providers to follow when they process requests for transmission service, including the 

issue Calpine raises in its comments about discrepancies between Entergy’s and SPP’s 

processes for requests for hourly non-firm transmission service. Calpine’s comment 

addresses the deadline for transmission customers to submit requests for non-firm hourly 

point-to-point service and the deadline for transmission providers to respond to requests 

for non-firm hourly point-to-point service. Standard 001-4.13 in Order No. 676 indicates 

that transmission providers should use their best efforts to respond to requests for nonfirm hourly point-to-point service that are submitted less than an hour prior to start and 

transmission providers should respond within 30 minutes to requests that are submitted 

more than an hour before start. In addition, in this NOPR we have provided additional 

clarity regarding the calculation of ATC and requirements for processing rollover 

requests. We also provide general guidance regarding which business practices should be 

filed as part of a transmission provider’s OATT and which should be posted on OASIS. 

Given this additional clarity and the business practices already mandated by Order 

No. 676, we seek comment on whether commenters believe additional standardization of 

request queue processing is necessary. If so, we seek comment on the specific issues 
Docket Nos. RM05-25-000 and RM05-17-000 - 280 – 

commenters believe are not clearly prescribed in Order No. 676 or this NOPR and which 

require additional mandatory queue processing business practices. 

c. Reservation Priority

394. 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. In 

the NOI, we asked whether the first-come, first-served approach to reservation priorities 

has resulted in a fair and equitable means of allocating transmission capacity when the 

transmission system is oversubscribed. If not, we asked whether an alternative approach 

should be implemented. 

 Comments

395. Most transmission providers and federal power agencies respond that the firstcome, first-served approach to allocating transmission service is the best alternative 

available.367 Several merchant generators and public power entities concur that no better 

alternative exists.368 Several commenters suggest that the first-come, first-served 

approach may provide an advantage to transmission customers who have the financial 

resources to purchase software and employ staff to continually monitor OASIS sites.369 

Santa Clara states that entities that have superior software and are able to consistently 

 367 E.g., Ameren, EEI, Nevada Companies, TVA, and WAPA. 

368 E.g., NRECA, Powerex, Public Power Council, Sempra, and TDU Systems. 

369 E.g., Bonneville and Santa Clara. 
Docket Nos. RM05-25-000 and RM05-17-000 - 281 – 

procure capacity to the exclusion of other market participants may have an unfair 

advantage. For the short-term market, Bonneville contends, the first-come, first-served 

approach has two defects: (1) it advantages larger and better-financed transmission 

customers, which can continually monitor OASIS sites and submit requests electronically 

the moment new ATC is posted; and (2) it results in arbitrary awards of transfer 

capability when one customer’s submission precedes a second customer’s submission by 

mere seconds. Bonneville suggests that the Commission modify the first-come, firstserved rule for awarding short-term firm point-to-point service capacity so that all 

requests submitted within a given time-frame are considered simultaneously submitted. 

396. Several commenters propose some version of priority preference for requests for 

transmission service that are pre-confirmed.370 Bonneville states that transmission 

customers flood the queue with unconfirmed requests to force competitors with higher 

queue positions to extend the length of their requests to retain their queue positions. 

397. Bonneville suggests that the Commission consider reducing the time transmission 

customers have to confirm requests for short-term transmission service after the 

transmission provider has accepted a request for short-term transmission service. 

Bonneville states that a shorter time-frame would clear the short-term firm transmission 

market more quickly and make it more difficult for transmission customers to tie up 

scarce transfer capability. 

 370 E.g., Bonneville, Entergy, and South Carolina E&G. 
Docket Nos. RM05-25-000 and RM05-17-000 - 282 – 

398. Powerex suggests that the Commission clarify its reservation priority standards so 

that when transmission providers make use of discounts in short-term service, price (not 

to exceed the ceiling price) should be the third-level tie breaking mechanism, with 

higher-priced requests of equal duration having greater priority and requests earlier in the 

open access same-time information system having right of first refusal to match 

subsequent requests. Powerex states that in the presence of discounting, the open access 

transmission tariff allows a higher value service (firm) to be sold at a lower price than a 

lower value service (non-firm) even in the same operating horizon, because price based 

displacement only applies to short-term non-firm transmission services. 

Discussion

399. In response 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, we seek comment 

regarding whether any such advantage would be mitigated if all requests submitted within 

a 5-minute window, with duration as a tie breaker, were deemed to have been submitted 

simultaneously. We also seek comment on whether transmission customers could game a 

5 minute equivalent priority standard to request transmission service only after another 

transmission customer has made a request. To the extent we adopt a 5 minute equivalent 

priority standard, we propose to allocate capacity on a pro rata basis, though we seek 

comment on other methods for allocating limited transmission capacity among equivalent 

priority requests of equal duration. 
Docket Nos. RM05-25-000 and RM05-17-000 - 283 – 

400. We also propose to change the priority rules to give priority to pre-confirmed 

requests. As a result, a pre-confirmed short-term request for firm transmission service 

would preempt any non-pre-confirmed short-term requests, regardless of duration. 

Similarly, a pre-confirmed request for long-term firm transmission service would 

preempt a request for long-term transmission service that is not pre-confirmed. We seek 

comment on whether this change to the reservation priority rules will alleviate concerns 

commenters have expressed regarding the flooding or jamming of the transmission queue 

by transmission customers who submit multiple requests for transmission service. 

401. We propose to add price as a tie-breaker in determining reservation queue priority 

when the transmission provider is willing to discount transmission service. Price would 

serve as a tie-breaker after pre-confirmation for those requests that are not yet confirmed. 

As a result, a pre-confirmed request for short-term firm point-to-point service would 

preempt another pre-confirmed request for short-term firm point-to-point service that has 

an earlier queue time, and an equal or shorter duration but a lower offer price. However, 

a request for short-term firm point-to-point service that is not pre-confirmed would not 

preempt a pre-confirmed request for short-term firm point-to-point service that has an 

earlier queue time, and an equal or shorter duration but a lower offer price. 

6. Designation of Network Resources

a. Qualification as a Network Resource

402. Taken together, the following sections of the pro forma OATT describe the 

resources a network customer can appropriately designate as a network resource. 
Docket Nos. RM05-25-000 and RM05-17-000 - 284 – 

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. 

403. The Commission has issued a number of orders that clarify which resources meet 

the criteria set out in sections 30.1 and 30.7 of the pro forma OATT. In MSCG, the 

Commission stated that network resources must be generating resources owned by the 

network customer or purchases of noninterruptible power under executed contracts that 

require the network customer to pay for the purchase.371 In WPPI, the Commission 

 371 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). 
Docket Nos. RM05-25-000 and RM05-17-000 - 285 – 

found that a network customer can designate as a network resource a system purchase 

that is not backed by a specific generator.372 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.373 In addition, the Commission stated that 

because the pro forma OATT requires a power purchase to be noninterruptible, thirdparty transmission arrangements to deliver the resource to the network have to be 

noninterruptible as well.374 In Illinois Power, the Commission found that a firm purchase 

need not be backed by a capacity purchase to qualify as a network resource.375

404. In the NOI, the Commission sought comment regarding whether network 

resources consisting of firm contracts that do not specify generation sources until the 

energy is scheduled (so-called “seller’s choice contracts”) are a problem. The 

Commission also sought comment on the specific difficulties entities have experienced 

with designation of network resources and asked what reforms are needed to the 

 372 Wisconsin Public Power Inc. v. Wisconsin Public Service Corp., 84 FERC 

¶ 61,120 at 61,650-51 (1998) (WPPI). 

373 Id.

374 Id. at 61,660. 

375 Illinois Power Co., 102 FERC ¶ 61,257 at P 14 (2003), reh'g denied, 108 FERC 

¶ 61,175 (2004) (Illinois Power). 
Docket Nos. RM05-25-000 and RM05-17-000 - 286 – 

designations provision in the pro forma OATT. 

 Comments

405. A number of commenters indicate that firm contracts that do not specify 

generation sources are acceptable network resources as long as the network customer 

specifies enough information for the transmission provider to identify how the contract 

power will enter its control area.376 Bonneville suggests that the customer should be 

required to identify the point(s) of receipt on the transmission provider’s system 

whenever it designates a network resource. EEI states that the designation of seller’s 

choice contracts as network resources is only problematic if the seller’s choice contract 

permits the seller to choose the flowgate path over which the energy will be delivered. 

EEI further explains that no issue is present if the seller is limited to a single path or 

flowgate. On the other hand, PNM-TNMP argues that allowing seller’s choice contracts 

to be considered network resources significantly complicates transmission planning, as 

virtually none of the information required by section 29.2 of the OATT can be provided. 

406. Several commenters cited specific difficulties with or suggested specific 

modifications to the network designation provisions of the tariff. APPA indicated that 

under the liquidated damages provisions in the EEI contract, it is the buyer’s 

responsibility to go out into the market to purchase replacement supplies (cover), and the 

seller then pays the buyer the difference between the contract price and the cover price. 

 376 E.g., Bonneville, EEI, Nevada Companies, Public Power Council, and TVA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 287 – 

APPA states that these provisions are not consistent with the concept of having to specify 

generation resources or contracts as network resources, since the actual source and 

supplier of generation may well change at a time when both wholesale power supplies 

and transmission capacity are at a premium. Ameren suggests that the Commission 

clarify that liquidated damages products cannot be designated network resources. 

Ameren states that a liquidated damages contract allows a supplier to walk away from a 

deal if it can obtain a price elsewhere high enough to offset the liquidated damages 

provisions. Ameren argues that liquidated damages contracts are financial instruments 

that produce no electricity. MidAmerican also contends that provisions for designating 

liquidated damages contracts as network resources should be eliminated. Southwestern 

urges the Commission to reform the OATT to make it clear that a firm purchased power 

contract with liquidated damages should be eligible to be considered a designated 

network resource. 

Discussion

407. We propose to maintain our current policy regarding the power purchase 

agreements that network customers may designate as network resources. In particular, a 

network customer will continue to be able to designate resources from system purchases 

not linked to a specific generating unit, provided the purchase power agreement is not 

interruptible for economic reasons, does not allow the seller to fail to perform under the 

contract for economic reasons, and the executed contract requires the network customer 
Docket Nos. RM05-25-000 and RM05-17-000 - 288 – 

to pay for the purchase. In addition, third party transmission arrangements to deliver the 

purchase to the network have to be noninterruptible as well. 

408. In response to comments that seller’s choice contracts are problematic because the 

network customer can provide limited, if any, information required by section 29.2 of the 

pro forma OATT, we reiterate that a request to designate a new network resource must 

include the information specified in section 29.2(v), including the source of supply, 

control area location, transmission arrangements, and delivery point(s) to the 

transmission provider's transmission system. 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. 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. 

409. In response to suggestions that liquidated damages products should not be 

designated network resources because they are interruptible for economic reasons, we 

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, a 

network customer may not designate as a network resource a purchase agreement that 

allows the seller to interrupt service for reasons other than reliability, but allows the 

buyer to force delivery at a higher price. In addition, a network customer may not 
Docket Nos. RM05-25-000 and RM05-17-000 - 289 – 

designate as a network resource a purchase agreement that requires a seller to pay the 
Docket Nos. RM05-25-000 and RM05-17-000 - 290 – 

buyer’s cost of replacement power when the seller chooses not to deliver energy for 

economic reasons. 

b. Documentation for Network Resources

410. Section 30.2 of the pro forma OATT stipulates that a network customer request the 

designation of a new network resource by a request for modification of service pursuant 

to an application under section 29 of the pro forma OATT, and section 29.2 stipulates 

that the network customer must provide specified information about its designated 

network resources. The Commission found in WPPI that transmission customers may 

need to document compliance with specific requirements for obtaining tariff service, 

possibly including contractual terms.377 The Commission went on to state that it 

expected a transmission provider’s merchant function to police its own compliance with 

tariff obligations.378

 Comments

411. LG&E suggests that the pro forma OATT require the transmission provider to 

have a process to verify that each load-serving entity has a contractual right to the 

resources they are designating. LG&E argues this would help eliminate concerns over 

double booking of resources by two parties. EPSA states that transmission providers 

have attempted to require customers to demonstrate that they have obtained contracts 

 377 WPPI at 61,660. 

378 Id. 
Docket Nos. RM05-25-000 and RM05-17-000 - 291 – 

covering an annual period, rather than allowing customers to provide reasonable advance 

notice for each contract during the service period. EPSA asks the Commission to 

prohibit this practice. 

Discussion

412. We clarify 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. 

While transmission providers are responsible for verifying that the network customer has 

provided all the information section 29.2 requires the network customer to provide, the 

transmission provider is not responsible for obtaining contractual terms to verify 

requirements in sections 30.1 and 30.7 of the pro forma OATT. 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. 

413. We propose to require the transmission provider’s merchant function as well as 

network customers to include a statement with each application to designate a new 

network resource that attests that: (1) the transmission customer owns or has committed 

to purchase the new designated network resource, and (2) the new 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. Similarly, we propose that all entities that submit an 

application for network service be required to include a statement with the application for 
Docket Nos. RM05-25-000 and RM05-17-000 - 292 – 

service 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. 

414. We propose that if the network customer does not include an attestation when it 

confirms its request, the transmission provider will notify the network customer within 15 

days of confirmation that its request is deficient. Wherever possible, the transmission 

provider will attempt to remedy deficiencies in the request through informal 

communications with the network customer. If such efforts are unsuccessful, the 

transmission provider will terminate the network customer’s request and change the 

status of the request on OASIS to "retracted." This termination will be without prejudice 

to the network customer submitting a new request that includes the required attestation. 

The network customer will be assigned a new priority consistent with the date of the new 

request. 

415. 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 

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 Enforcement 

Policy Statement. We encourage the transmission provider and other market participants 

to use the Commission’s Enforcement Hotline to report instances when they believe a 
Docket Nos. RM05-25-000 and RM05-17-000 - 293 – 

network customer has designated as a network resource a resource that does not meet the 

criteria for network resources. 

c. Undesignation of Network Resources

416. 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 allows the network customer to terminate the designation of all or part of a 

generating resource as a network resource at any time, though the network customer 

should provide notification to the transmission provider as soon as reasonably 

practicable. 

417. 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 

current 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, 

as set forth in section 29 of the pro forma OATT, that the same generation resource be 

designated as a network resource effective with the end of its power sale.379

 379 Order No. 888-B at 62,093. 
Docket Nos. RM05-25-000 and RM05-17-000 - 294 – 

418. In the NOI, the Commission sought comment on whether network customers 

should be allowed to “undesignate” portions of their designated network resources on a 

short-term basis in order to make firm sales from these resources. 

 Comments

419. Most commenters suggest that the Commission continue to allow network 

customers to undesignate a portion of their designated network resources on a short-term 

basis in order to make firm sales.380 APPA argues that the ability of network customers 

to undesignate their network resources on a short-term basis is an important aspect of 

Order No. 888-B and should be preserved. APPA states that the flexibility afforded to 

network resource customers allows them to lay off excess power supplies that they do not 

need to serve their designated loads during off-peak demand periods. APPA and EEI 

contend that this increases the number of wholesale sellers in the market during non-peak 

periods, and this supports wholesale competition for power supply sales. 

420. Several commenters suggest that network customers should have the same right as 

transmission providers to undesignate network resources to make off-system sales. 381 

APPA states that the Commission should make explicit the requirement that the 

transmission provider must provide the same flexibility to its network customers as it 

 380 E.g., APPA, EEI, Entergy, Nevada Companies, Public Power Council, 

Southern, and TVA. 

381 E.g., APPA, NRECA, and Public Power Council. 
Docket Nos. RM05-25-000 and RM05-17-000 - 295 – 

does to its own merchant function in designating and terminating network resources. 

421. NRECA asserts that public utility transmission providers must be required to 

undesignate resources or portions thereof in order to make firm sales out of generation 

fleets that they have designated as a network resource. 

Discussion

422. We propose to continue to allow network customers to undesignate a portion of 

their network resources on a short-term basis to make off-system sales. We reiterate that 

a network customer may redesignate the resource by making a request to designate a new 

network resource. In response to comments that the transmission provider also should be 

required to undesignate network resources when the transmission provider makes firm 

off-system sales, we reiterate that the transmission provider must abide by both the 

requirement in section 28.2 of the pro forma OATT to designate its network resources in 

the same manner as network customers and the prohibition in section 30.1 of the pro 

forma OATT against making firm sales from its designated network resources. That is, 

the transmission provider and all network customers must designate their network 

resources and are prohibited from making firm sales from designated network resources. 

To the extent the transmission provider or a network customer wants to make a firm sale 

from a network resource, it must undesignate the resource pursuant to section 30.3 of the 

pro forma OATT. The network customer, including the transmission provider itself, can 

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. 
Docket Nos. RM05-25-000 and RM05-17-000 - 296 – 

423. We seek 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. 

7. Clarifications Related to Network Service

Secondary Network Service

424. Section 28.4 of the pro forma OATT allows a network customer to deliver 

economy energy purchases to its network load from non-designated network resources on 

an as-available basis without additional charge. In Order No. 888, the Commission 

described economy energy purchases as energy that displaces firm network resources.382

425. The use of secondary network service to deliver purchased power when a network 

customer is making off-system sales was 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.383 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.384 In accepting 

 382 Order No. 888 at 31,751. 

383 Idaho Power Co., 103 FERC ¶ 61,182 at P 2 (2003) (Idaho Power). 

384 Id. at P 4. 
Docket Nos. RM05-25-000 and RM05-17-000 - 297 – 

the settlement, the Commission stated that “[i]t is axiomatic that the native load priority 

cannot be used to complete sales that are not necessary to serve native load.”385 In 

MidAmerican, the Commission issued an audit report that contained a finding that 

MidAmerican’s wholesale merchant function used network service instead of point-topoint service to deliver short-term energy purchases to its control area that were not used 

to serve MidAmerican’s native load.386

 Comments

426. South Carolina E&G asks the Commission to clarify whether specific methods 

used to bring sellers and buyers together in the wholesale market are appropriate under 

the pro forma OATT in its current form. South Carolina E&G notes that as a utility’s 

native load forecasts evolve into real-time conditions, the utility may need to sell off 

excess energy. South Carolina E&G notes further that, as inexpensive sources of power 

become available off-system, the utility may engage in economy purchases of power for 

native load. South Carolina E&G asserts that such practices clearly benefit the market 

and safeguard native load customers’ interests by ensuring that economy purchases 

minimize the price of consumers’ power and/or giving the utility a market outlet for 

excess energy, thus avoiding the uneconomic backing down of lower cost generating 

 385 Id.

386 MidAmerican Energy Co., 112 FERC ¶ 61,346 at P 6 (2005).
Docket Nos. RM05-25-000 and RM05-17-000 - 298 – 

units while retaining higher cost prescheduled purchases. South Carolina E&G urges the 

Commission to support the continuation of such practices. 

Discussion 

427. We propose to clarify that a network customer may not use secondary network 

service to bring energy onto its system to support an off-system sale if the purchased 

power does not displace the customer’s own higher cost generation. We propose to 

modify the section 28.4 of the pro forma OATT to clarify that a network customer may 

use secondary network service to deliver economy energy and we propose to add a 

definition for “economy energy” to the pro forma OATT. We propose 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. 

428. While we reiterate that secondary network service may be used only to serve a 

network customer’s designated network load, we do not intend to discourage market 

participants from identifying opportunities to profitably purchase for resale. We simply 

intend to ensure that all market participants compete on a comparable basis and use pointto-point service to complete all segments of a purchase for resale off-system. 

429. We also do not intend to discourage network customers from purchasing offsystem energy to lower the cost of serving network loads. A network customer may use 

secondary network service in hours when it is also making off-system sales. However, 

the network customer may do so only to deliver purchases that qualify as economy 
Docket Nos. RM05-25-000 and RM05-17-000 - 299 – 

energy purchases. In response to South Carolina E&G’s observation that a utility’s 

native load forecasts evolve in real-time to the point that the utility may need to sell off 

excess energy that was purchased off-system, we note that our definition would allow a 

network customer to use network service to deliver off-system purchases when the 

network customer purchases the energy with the intent to serve native load. 

430. In enforcing this policy, we will apply the definition of “economy energy” at the 

time the network customer commits to purchase energy. For instance, we will not take 

issue if a network customer uses secondary network service to deliver an hour-ahead 

purchase that costs less than the network customer’s generation cost in the hour of 

operation. Similarly, we will not question the use of secondary network service by a 

network customer to deliver a day-ahead off-system purchase that costs less than the 

network customer’s forecast generation cost, even if real-time system conditions evolve 

so that the realized generation cost is less than the cost of the purchased energy. We also 

would not take issue with a network customer that uses network service to deliver offsystem block energy because the purchased energy is more economic than using its 

network resources, but makes off-system sales during some hours when the block energy 

purchase is scheduled. In other words, in enforcing this policy, we will apply the 

definition of “economy energy” as it applies to the entire period covered by the block 

purchase and not to a single hour within the block. 

“[O]n an as-available basis” 

431. Section 28.4 of the pro forma OATT allows a network customer to use secondary 
Docket Nos. RM05-25-000 and RM05-17-000 - 300 – 

network service to deliver economy 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. 

Discussion

432. We propose to modify section 28.4 of the pro forma OATT by clarifying that a 

network customer need not file an application for network service to receive secondary 

network service, but that all other requirements of Part III of the pro forma OATT (except 

for transmission rates) apply to secondary network service. In other words, a network 

customer must request secondary network service on OASIS in a manner consistent with 

pro forma OATT sections 18.1 and 18.2 (Procedures for Arranging Non-Firm Point-ToPoint Transmission Service). 

Redirect of Network Service

433. 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. However, we are aware 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. 

Discussion

434. We propose to clarify that network customers may not redirect network service in 

a manner comparable to the way customers redirect point-to-point service. Unlike point-
Docket Nos. RM05-25-000 and RM05-17-000 - 301 – 

to-point service that is based upon a contract-path model consisting of a designated point 

of receipt and point of delivery, network service involves no identified contract path and 

is therefore not a directable service. Rather, network service provides for the integration 

of designated network resources and loads using the entire transmission grid in a manner 

comparable to the transmission provider’s use of the transmission grid to serve its native 

load customers. When a network customer wants to substitute one designated network 

resource for another, it should terminate the designation of the existing network resource 

and designate a new network resource. The network customer can then 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. 

8. Transmission Curtailments 

435. Section 1.7 of the pro forma OATT defines curtailment as “a reduction in firm or 

non-firm transmission service in response to a transmission capacity shortage as a result 

of system reliability conditions.” Curtailment provisions for point-to-point service are set 

forth in sections 13.7 and 14.7 for firm and non-firm transmission services respectively 

and the curtailment provisions for network service are contained in section 33. 

Complaints regarding improper curtailment of service by transmission providers have 
Docket Nos. RM05-25-000 and RM05-17-000 - 302 – 

been made in a variety of proceedings and the Commission has found cases of improper 

curtailment in the past.387 

436. In the NOI, the Commission asked whether there is evidence of improper 

curtailment practices by public utility transmission providers or customers that warrants 

reforms to the pro forma OATT. If there is, we requested that commenters provide 

specific examples of such practices. We also asked whether transmission providers 

engaging in improper curtailments should be subject to monetary penalties or other 

remedies for market manipulation. 

Comments

437. EEI argues that there do not appear to be many instances of improper curtailments 

and many utilities state that they are not aware of any improper curtailments by public 

utility transmission providers. For example, Southern states that curtailments are 

performed on a non-discriminatory basis, in accordance with applicable OATT 

provisions. Ameren, KCP&L, and PNM-TNMP state that they are not aware of any 

improper practices that would warrant reforms to the pro forma OATT. APPA does not 

advocate changes to the pro forma OATT regarding curtailment, stating that its members 

express more concerns about the denial of service prior to and at the time of scheduling 

than they do regarding curtailment of service once it has commenced. However, APPA 

 387 See, e.g., Consolidated Edison Co. of N.Y. v. Public Serv. Elec. & Gen. Co., 

108 FERC ¶ 61,120 (2004). 
Docket Nos. RM05-25-000 and RM05-17-000 - 303 – 

also notes that most of its members use firm service that is unlikely to be interrupted once 

it is scheduled. Public Power Council, Snohomish, MEAG and Salt River concur with 

APPA that OATT reforms are not needed for curtailments. 

438. Transmission customers, particularly IPPs, generally have a different view, 

arguing that the reasons for curtailment are difficult to discern, and that information is 

often insufficient to determine whether curtailments have been performed correctly. 

Northwest IPPs state curtailments frequently appear arbitrary. Powerex argues that 

incomplete postings on many transmission systems and the lack of transparency in 

curtailment data could mask improper curtailment. Calpine states that it is usually 

difficult to determine whether a curtailment of service is truly justified by system 

reliability factors because the operational facts underlying the utility’s curtailment 

decision are unknown. It argues that the criteria for utility curtailment decisions are not 

standardized, making it difficult to determine the propriety of curtailment decisions, 

particularly when curtailment is internal to a single area and not performed through the 

NERC TLR process. Calpine recommends that the terms and conditions for curtailments 

be standardized by the new reliability organizations created by EPAct 2005, that such 

terms and conditions be made a formal part of the pro forma OATT and the OATTs of 

public, private and federal utilities, and that these be posted on the transmission 

provider’s OASIS. Calpine further recommends that regional NERC organizations be 

requested to audit the curtailment practices of all utilities that are not members of an 

RTO/ISO. Constellation asserts that TLRs are a “blunt and inefficient mechanism” for 
Docket Nos. RM05-25-000 and RM05-17-000 - 304 – 

curtailment and calls for a requirement that transmission providers provide redispatch 

options. 

439. In reply to claims that vertically integrated utilities provide inadequate information 

on curtailments, Southern states that existing OASIS requirements already require 

utilities to post a considerable amount of information on curtailments, and that the 

information currently posted is adequate to meet customers’ needs. Nevertheless, 

Southern also states that while those rules have been effective in achieving their intended 

purpose, incremental additions to the information that is available through OASIS could 

assure customers that they have all of the information they need to make prudent 

decisions about transmission service and that they are being treated in a fair, equitable, 

and non-discriminatory way. 

440. Commenters appear divided on the issue of whether there should be penalties for 

improper curtailments. The most common view, expressed by EEI and others, is that 

penalties for improper curtailments should be assessed only if the Commission finds that 

the transmission provider imposed the curtailment with the intent to treat a customer in an 

unduly discriminatory or preferential manner. Other commenters expressed a wide range 

of views. Alcoa states that improper curtailments should be the subject of monetary 

penalties. Santa Clara contends that transmission providers should be fully liable for any 

damages caused by improper curtailments. On the other hand, Southern argues that 

curtailment is a reliability issue and it would be unwise to subject transmission providers 

to after-the-fact assessments of their curtailment decisions. KCP&L notes that the 
Docket Nos. RM05-25-000 and RM05-17-000 - 305 – 

responsibility for calling a TLR rests with the reliability coordinator, who makes 

decisions based on the NERC standard, so that penalties for improper curtailment activity 

should be a subject for the ERO. 

Discussion 

441. The Commission reminds both transmission providers and customers that our 

regulations require posting of transmission curtailment information on OASIS. The 

OASIS regulations state:

When any transaction is curtailed or interrupted, the Transmission Provider must 

post notice of the curtailment or interruption on the OASIS, and the Transmission 

Provider must state on the OASIS the reason why the transaction could not be 

continued or completed. 

(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 three 

years.388 

(iii) 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.389

442. Those commenting that they have inadequate information about curtailments do 

not clearly state whether the source of this deficiency lies in: (1) the inadequacy of our 

 388 We note that we are proposing to change this information retention period to 

five years, consistent with our other proposed changes to the OASIS information 

retention provisions. 

389 18 CFR 37.6(d)(3) (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 306 – 

standards, (2) inadequate compliance with these standards, (3) difficulties in dealing with 

the way the information is provided, or (4) some other area. We are, however, mindful 

that objective review of curtailments can require a considerable amount of information, 

some of which may not be provided under the present OASIS regulations, or may be 

provided in an inefficient manner. For example, we recognize that it is difficult for a 

customer to determine what network resources were available to the transmission 

provider that could have been redispatched consistent with pro forma OATT sections 

30.5 and 33.2 to relieve the transmission constraint that led to a transmission curtailment. 

Another example may be discerning which discrete transaction(s) could be curtailed on a 

non-discriminatory basis to effectively relieve the constraint consistent with pro forma

OATT section 13.6. We seek comment on whether additional requirements would 

improve the transparency of transmission curtailment information and the ability of 

customers to make use of that information. 

443. With respect to the imposition of penalties, the Commission recognizes that the 

transmission curtailment decision is a reliability decision that should be based on 

applicable reliability standards. Moreover, we note that the need for transmission 

curtailment depends on many factors outside the control of an individual transmission 

provider, including loop flows throughout an interconnection. Accordingly, we will not 

propose generic penalties for improper transmission curtailments in this rulemaking. 

However, the absence of generic penalties should not be construed to mean that we will 

tolerate intentional behavior that subjects customers to unduly discriminatory or 
Docket Nos. RM05-25-000 and RM05-17-000 - 307 – 

preferential actions. We remain vigilant in monitoring for intentionally discriminatory 

provision of transmission service, and stand ready to use our enforcement powers and 

penalty authority when needed. 

9. Standardization of Rules and Practices

444. In Order No. 888, the Commission required each public utility that owns, controls, 

or operates facilities used for transmitting electric energy in interstate commerce to file, 

pursuant 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 such transmission service (e.g., public utility business practices) are not 

reflected in the pro forma OATT. Only when a public utility adopts a rule, standard or 

practice that significantly affects its rates and services has the Commission required it to 

make a filing pursuant to FPA section 205 to amend its OATT.390 The Commission has 

applied this policy using a “rule of reason” test.391 

445. 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 

 390 E.g., Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985). 

391 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 only with 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. RM05-25-000 and RM05-17-000 - 308 – 

the business practices manuals of the Midwest ISO 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 

a FPA section 205 filing because “they mostly involve general operating procedures.”392 

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. 

There, the Commission found that the details contained in the standards are practices that 

may affect the terms and conditions of service significantly, and therefore, under the 

Commission’s “rule of reason,” must be filed under FPA section 205. 393 

446. In the NOI, the Commission asked: (1) Whether all rules, standards and practices 

 392 Midwest Independent Transmission System Operator, Inc., 108 FERC ¶ 61,163 

at P 656, 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). 

393 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 (2005) 

(requiring that the SPP OATT provide sufficient information for market participants to 

fully understand SPP’s implementation of an imbalance market), reh’g dismissed, 

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. RM05-25-000 and RM05-17-000 - 309 – 

should be required to be included in public utilities’ OATTs? (2) If not all, which of such 

rules, standards and practices should be included in public utilities’ OATTs? and 

(3) Should rules, standards and practices not required to be included in public utilities’ 

OATTs be required to be posted on OASIS to increase transparency? 

Included in Open Access Transmission Tariffs

447. Some commenters argue that the rules, standards and practices governing the 

provision of transmission service should be included in public utilities’ OATTs.394 

Occidental states that the inclusion of rules, standards and practices governing the 

provision of transmission service in public utilities’ OATTs will add much needed clarity 

as to how transmission service is provided. EPSA states that while it may not be 

necessary, or desirable, to require all business practices to be incorporated into the 

OATT, there have been instances where transmission providers have adopted business 

practices that are inconsistent with their OATT requirements or that should have been 

filed as OATT amendments. Some commenters also support the inclusion of the NAESB 

standards in the OATT.395 

448. In contrast, some commenters oppose including rules, standards and practices in 

the OATT.396 EEI argues that rules, standards and practices should not be included as 

 394 E.g., Occidental, TAPS, and Williams. 

395 E.g., Salt River and Snohomish. 

396 E.g., BPA, EEI, MidAmerican, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 310 – 

part of an OATT unless they significantly affect rates and service under the OATT. EEI 

states that this is consistent with the Commission’s current practice for the inclusion of 

manuals in an OATT. Indicated New York Transmission Owners state that the inclusion 

of rules, standards and practices in the OATT is unnecessary and would administratively 

encumber any future revisions to the practices and rules by requiring conforming tariff 

filings. 

Posted on OASIS

449. Several commenters believe it would be appropriate to post rules, standards and 

practices on public utilities’ OASIS sites.397 For example, EEI states that it would be 

appropriate to post all rules, standards and practices that are not part of the OATT on a 

transmission provider’s OASIS. APPA asserts that, in particular, transmission providers 

should post the methodologies they use to develop ATC and ATC calculations should be 

periodically verified by an independent third party.398 

450. Other commenters contend that rules, standards and practices should be posted on 

public utilities’ OASIS sites only when they are not required to be filed.399 TAPS argues 

that any rules, standards and practices not required to be filed must be publicly posted on 

the transmission provider’s OASIS to provide needed transparency, because including 

 397 E.g., APPA, BPA, EEI, EPSA, MidAmerican, and Southern. 

398 See supra Part V.A addressing posting requirements for ATC calculation. 

399 E.g., Progress Energy and TAPS. 
Docket Nos. RM05-25-000 and RM05-17-000 - 311 – 

essential terms in business practices that are not posted makes it very difficult for 

customers to understand if they are being treated fairly by the transmission provider. 

TDU Systems asserts that requiring posting on transmission providers’ OASIS sites of 

any standards and practices not included in their OATTs would facilitate transactions 

across several transmission provider systems, especially where transmission providers are 

not participating in RTOs or ISOs.400 Williams goes one step further and recommends 

that the Commission require that transmission providers both file with the Commission 

and post on their OASIS sites, all policies, practices and interpretations used or relied 

upon to evaluate a request for transmission service. 

Discussion

451. There appears to be broad consensus among the commenters 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. We agree and propose to 

require transmission providers to post on OASIS all of their rules, standards and practices 

that relate to transmission services. We believe this proposal will provide greater 

transparency and mitigate the potential for undue discrimination against customers taking 

 400 Suez Energy NA emphasizes that the posting of rules, standards, and practices 

on OASIS merely ensures that they are transparent, it does not ensure that they are nondiscriminatory. 
Docket Nos. RM05-25-000 and RM05-17-000 - 312 – 

transmission service under the transmission provider’s OATT.401 However, we seek 

comment on how to determine what “relates” to transmission service to facilitate a 

consistent interpretation and to minimize discretion on what rules, practices and standards 

should be posted on OASIS.402 

452. Commenters presented wide ranging positions on the issue of what rules, 

standards and practices to include in the OATT. We do not propose to modify our 

existing policy on this issue at this time.403 We agree with EPSA’s 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 businesses 

practices and respond to the requests of customers. Additionally, we believe that 

requiring transmission providers to file all of their rules, standards and practices in their 

 401 We clarify that posting rules, practices and standards on the transmission 

provider’s OASIS – 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 

utilities, 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 www.ferc.gov/custprotect/enforce-hot.asp. 

402 We note that certain rules and practices are already required to be posted on 

OASIS. See, e.g., Order No. 889; 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. 

403 See supra notes 391-393 and accompanying text. 
Docket Nos. RM05-25-000 and RM05-17-000 - 313 – 

OATTs would be impractical and potentially administratively burdensome.404 

453. We propose to require, however, that creditworthiness and security requirements 

be included in a transmission provider’s OATT. The creditworthiness provision in 

section 11 of the pro forma OATT authorizes transmission providers to require 

“reasonable credit review procedures” in accordance with “standard commercial 

practices,” to determine the ability of transmission customers to meet service obligations. 

Furthermore, to protect transmission providers from the risk of non-payment, the 

provision authorizes the transmission provider to require as security a letter of credit or 

other forms of security consistent with the Uniform Commercial Code. In the 

Creditworthiness Policy Statement, the Commission explained that non-RTO or -ISO 

transmission providers generally have not incorporated creditworthiness or security 

requirements into their OATTs.405 The Commission stressed that transparency of credit 

procedures and security requirements can enhance market certainty and liquidity by 

allowing customers to determine for themselves the information they need to demonstrate 

creditworthiness and the amount and type of security they need to receive transmission 

service. In interpreting the “reasonable credit review procedures” requirement in section 

 404 Of course, we will require the filing of certain rules, standards and practices 

when circumstances require. In Order No. 676, the Commission, among other things, 

incorporated certain business standards developed by NAESB by reference into the 

Commission’s regulations and required public utilities to file revisions to their OATTs to 

include these standards. Order No. 676 at P 20. 

405 Policy Statement on Electric Creditworthiness, 109 FERC ¶ 61,186 at P 9 

(2004) (Creditworthiness Policy Statement). 
Docket Nos. RM05-25-000 and RM05-17-000 - 314 – 

11 of the pro forma OATT, the Commission stated that it expected transmission providers 

to post on their OASIS sites the process and methodologies used to evaluate a potential 

customer’s creditworthiness and calculate the necessary security.406 But it also stated that 

it would “consider standardizing credit procedures through a generic rulemaking if 

necessary to prevent undue discrimination.”407 

454. Our preliminary conclusion is that a transmission provider’s OATT should 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. We therefore propose 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. 

455. In the Creditworthiness Policy Statement, the Commission explained that, to 

assess an applicant’s credit risk, transmission providers should use both qualitative 

factors, such as the local regulatory environment or the applicant’s history and financial 

policies, and quantitative factors, such as information included on the applicant’s 

 406 Id. at P 12. The Commission explained that all transmission providers 

(including RTOs and ISO) were expected to “(1) make their credit-related practices more 

transparent and comprehensive; (2) post on their [OASIS sites] the procedures that they 

use to do their credit analyses; and (3) provide a customer with a written analysis setting 

forth how that entity applied its credit standards to that customer, if that customer is 

required to provide security.” Id.

407 Id. at P 15. 
Docket Nos. RM05-25-000 and RM05-17-000 - 315 – 

financial statements.408 We propose to require the new Attachment L to include such 

quantitative and qualitative criteria to determine the level of secured and unsecured 

credit. We also propose 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. We propose to allow these basic elements to be 

supplemented with a credit guide or manual to be posted on OASIS. 

456. Though we are proposing to require transmission providers to incorporate the 

creditworthiness and security methodologies into their OATTs, we recognize that there is 

a balance here between the burden on the transmission provider of adding these 

methodologies to its OATT and the need for Commission review and approval if 

methodologies frequently change. We seek comment on whether the proposal is unduly 

burdensome. 

 408 Id. at P 13 & nn.13-14. An evaluation using both sets of factors would allow 

an applicant without a credit rating or a strong balance sheet, but with solid credit, to 

meet the creditworthiness criteria. Id. at P 14. 
Docket Nos. RM05-25-000 and RM05-17-000 - 316 – 

10. OATT Definitions 

457. In the NOI, the Commission requested comment on whether new or amended pro 

forma OATT definitions were necessary. The Commission also noted that new section 

215(a)(4) of the FPA, which was adopted as part of EPAct 2005, defines the term 
Docket Nos. RM05-25-000 and RM05-17-000 - 317 – 

“reliable operation.”409 We therefore asked whether this definition should be 

incorporated in the pro forma OATT. 

458. Though MidAmerican urges the Commission to incorporate the definition of 

“reliable operation” into the pro forma OATT, other commenters argue that the definition 

of reliable operation should not be included in the pro forma OATT.410 Southern argues 

that the definition of reliable operation included in section 215 of the FPA would impose 

a higher standard on transmission providers than is currently required by well-established 

NERC standards. Southern and EEI assert that the system is not planned to be able to 

guarantee that operations will not be impaired under any conditions. Southern argues that 

transmission providers should not be held to a higher standard of having to ensure that 

the system can continue to be operated even if a “sudden disturbance, including a 

cybersecurity incident or unanticipated failure of system elements” occurs. 

459. Along with Southern, EEI contends that the ERO should establish standards 

related to reliable operation. EEI states that section 215 of the FPA simply gives the 

Commission jurisdiction over reliability standards, which are defined as standards for the 

 409 EPAct 2005 sec. 1211(a) (to be codified at FPA section 215(a), 16 U.S.C. 

824o). Section 215(a)(4) defines “reliable operation” as “operating the elements of the 

bulk power system within equipment and electric system thermal, voltage, and stability 

limits so that instability, uncontrolled separation, or cascading failures of such system 

will not occur as a result of a sudden disturbance, including a cybersecurity incident, or 

unanticipated failure of system elements.” 

410 E.g., EEI, Powerex, Snohomish, Southern, Suez Energy NA, and TAPS. 
Docket Nos. RM05-25-000 and RM05-17-000 - 318 – 

reliable operation of the transmission system; it does not require transmission providers 

to meet a “reliable operation” standard. This is an important distinction, EEI continues, 

because while a transmission provider may adopt reasonable reliability standards, that 

does not guarantee that it will in all instances meet a “reliable operation” requirement, 

which would require the transmission provider to in all instances prevent instability, 

uncontrolled separation or cascading failures despite sudden disturbances, cybersecurity 

incidents, or unanticipated failures of system elements. EEI and Southern contend that 

because the ERO will implement the directives of Congress contained in section 215, the 

ERO will be best suited to establish the reliability standards that incorporate principles of 

reliable operation. 

460. TAPS suggests that what is more important than adding a “reliable operation” 

definition is making explicit in the tariff what the Commission stated in its Policy 

Statement on Matters Related to Bulk Power System Reliability (Reliability Policy 

Statement)411 – that transmission provider obligations under the pro forma OATT are 

subject to an overriding “Good Utility Practice” requirement that includes compliance 

with NERC reliability standards or more stringent regional reliability council standards. 

 411 Policy Statement on Matters Related to Bulk Power System Reliability, 

107 FERC ¶ 61,052 at P 23, clarified, 108 FERC ¶ 61,288 (2004); Supplement to Policy 

Statement on Matters Related to Bulk Power System Reliability, 110 FERC ¶ 61,096 

(2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 319 – 

Discussion

461. We propose to require transmission-owning public utilities to modify the 

definition of Good Utility Practice in their respective OATTs to reference the reliable 

operation definition adopted in section 215 of the FPA. We propose to take this action 

for two reasons. First, the Commission indicated in the Reliability Policy Statement that 

it expects public utilities operating transmission facilities under the pro forma OATT to 

conform to prevailing reliability standards. The Commission finds that referencing the 

reliable operation definition in section 215 of the FPA satisfies our requirement that 

transmission providers provide safe and reliable transmission service to customers taking 

service under the pro forma OATT. Second, we are mindful of the obligation placed on 

“all users, owners and operators of the bulk power system” under section 215(b) of the 

FPA to “comply with reliability standards” that will take effect under this section. Those 

reliability standards must “provide for reliable operation of the bulk-power system.”412 

When the ERO is certified by the Commission and we approve its reliability standards, 

those standards will be based on the same definition of reliable operation we propose to 

incorporate into the pro forma OATT. We agree with EEI and Southern that the ERO is 

best suited to develop reliability standards for the Commission’s approval, but our 

proposal to incorporate the definition of reliable operation does not establish a reliability 

standard; rather, we believe it reflects Congress’s benchmark for acceptable utility 

 412 Section 215(a)(3) of the FPA. 
Docket Nos. RM05-25-000 and RM05-17-000 - 320 – 

practice. It therefore belongs in our definition of Good Utility Practice in the pro forma

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

462. In addition to amending the definition of Good Utility Practice, we propose to add 

a definition for “non-firm sales” to clarify section 30.4 of the pro forma OATT. A 

number of transmission providers have modified section 30.4 of the OATT to state that 

“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” (emphasis added). We propose to define 

“non-firm sales” as “an energy sale for which delivery or receipt of the energy may be 

interrupted for any reason or for no reason, without liability on the part of either the 

buyer or seller.” This is the definition of non-firm sales used in a number of industrystandard master power sales agreements, including the EEI Master Purchase and Sale 

Agreement. We propose to clarify that, for the purposes of applying section 30.4 of the 

pro forma OATT, energy sales that can only be interrupted to maintain system reliability 

will be considered firm sales. 

463. We also propose to add two new definitions that are required to implement our 

proposed reforms. For example, we propose a definition of “affiliate” in section 1.1 of 

the revised pro forma OATT incident to our proposed change to the pricing of reassigned 

capacity. We also propose a new definition of “pre-confirmed application” in section 

1.40 of the revised pro forma OATT incident to our proposal to give priority to requests 

that are pre-confirmed. 
Docket Nos. RM05-25-000 and RM05-17-000 - 322 – 

E. Enforcement 

1. General Policy 

a. Compliance Review Regime 

Comments

464. A number of commenters indicate that a strong program to audit compliance with 

the pro forma OATT is crucial to preventing undue discrimination in the provision of 

transmission service. APPA argues that the Commission should establish a regime of 

systematic tariff compliance reviews because the OATT is at bottom a behavioral remedy 

rather than a structural one, so active Commission oversight is necessary. In addition, 

APPA notes that OATT transmission customers (especially network customers that are 

dependent upon the transmission systems of their neighboring public utility OATT 

transmission providers) are often reluctant to open the “can of worms” that filing a 

section 206 complaint against their transmission providers entails. Powerex urges the 

Commission to establish systematic tariff compliance audits as a monitoring tool because 

remedies and penalties alone are structurally ill-suited to address the myriad of 

idiosyncratic deviations from the Commission's policies and standards that currently 

exist. TAPS asserts that, while customer complaints are an indication that something is 

awry, the lack of transparency makes it very hard for customers to detect discrimination 

and tariff violations on the part of the transmission provider. TAPS suggests that 

customers often conclude that a complaint process is not cost effective because even if 
Docket Nos. RM05-25-000 and RM05-17-000 - 323 – 

they ultimately prevail, they will have lost out on the purchase opportunity that prompted 

the complaint. 

Discussion 

465. The Commission intends to maintain a strong audit program to determine whether 

transmission providers and transmission customers are in compliance with the new pro 

forma OATT. This audit program will include operational audits similar to the OATT 

compliance components of audits conducted by Commission staff in the past. 

466. These audits will determine compliance with specific provisions of the OATT. 

Staff’s findings and recommendations will be detailed in public audit reports issued in 

accordance with the Commission’s authority. If an audit is contested, it will be disposed 

of consistent with the Commission’s final rule on disposition of contested operational 

audits. The Commission staff’s compliance audits historically have included the 

collection of information regarding the audit target’s overall operations. In this vein, the 

Commission staff’s OATT compliance audits may also collect information regarding 

implementation of a transmission provider’s OATT, with the intent that Commission staff 

may share the information it gathers with the Commission subject to all applicable ex 

parte rules. 

b. Use of Independent Third Party Audits 

Comments

467. A number of commenters indicate that the Commission should not rely on third 

party audits as the primary means of ensuring compliance with the OATT. APPA states 
Docket Nos. RM05-25-000 and RM05-17-000 - 324 – 

that if an OATT Transmission Provider retains and pays an “independent reviewer” to 

prepare compliance audit reports, someone will inevitably question the reviewer’s 

independence. Therefore, APPA argues that it might be better for the Commission itself 

to prepare the reports, or to retain a consultant to do so. Southern suggests that the 

Commission’s existing mechanisms, coupled with new rules that will ensure that all 

regulated entities subject to investigations or audits are afforded their full due process 

rights, should be adequate to ensure compliance with OATT provisions. 

468. A number of commenters also indicate that the Commission should require third 

party audits for frequent abusers. EEI suggests that a transmission provider that is found 

to have a systematic or continuing violation of the OATT could be required to hire an 

independent reviewer to monitor its future compliance for a period of time after the 

violation occurred. TVA suggests that, if a particular transmission provider repeatedly 

misapplies its OATT, the Commission should at that point consider requiring that 

transmission provider to hire an independent monitor for a defined period of time as a 

remedy for those actual infractions. NRECA argues that those transmission providers 

who are consistently in violation or who do not cure audit findings in a timely manner 

should see both an increase in frequency and further scrutiny from the audit process. 

Discussion

469. We propose to have Commission staff conduct audits of compliance with the new 

OATT. Commission staff is in a unique position to conduct OATT compliance audits 

and recommend remedial action consistent with previous audits. In addition, entities 
Docket Nos. RM05-25-000 and RM05-17-000 - 325 – 

audited by Commission staff now have clear and assured due process rights as the result 

of Order No. 675. 

470. We may require third party audits as part of an individual compliance plan we 

order an audited party to undertake when we issue the Commission staff’s audit report. 

The Commission staff monitors compliance with all of its audit recommendations as part 

of its regular practice. We may, in selected cases, decide to enhance this regular 

monitoring by requiring an audited party to hire an independent reviewer to continue 

compliance audits after the Commission staff’s audit has ended. We could take such 

action in response to a number of circumstances, including, but not limited to, 

identification of systematic OATT violations, violations that require on-going 

monitoring, or a pattern of repeated OATT violations. Under these circumstances, the 

audited party should bear the burden of on-going compliance monitoring. If we decide to 

order independent OATT compliance audits as part of an individual audited party’s 

compliance plan, we will specify the scope and duration of the audits. 

2. Civil Penalties

a. Background

471. The NOI observed that the existing OATT allows transmission providers to 

impose certain operational penalties on customers for tariff violations, but does not 

address the adverse consequences to a transmission provider who violates its OATT. It 

also summarized the broad variety of remedies and sanctions available for enforcement of 
Docket Nos. RM05-25-000 and RM05-17-000 - 326 – 

its rules and regulations, including the enhanced civil penalty authority provided by 

EPAct 2005.413 

472. In the NOI, the Commission asked for comments on whether we should address 

the issue of remedies or penalties against transmission providers as part of OATT reform. 

It also asked if transmission providers should be subject to revocation of their marketbased rate authority for certain OATT violations, and if certain violatins should be 

considered market manipulation under the Market Behavior Rules414 and section 1283 of 

EPAct 2005.415

473. Subsequent to the NOI, on October 20, 2005 the Commission issued its 

Enforcement Policy Statement, which discusses the factors the Commission will take into 

account in determining remedies and sanctions for violations, including civil penalties.416 

Also, in EPAct 2005, Congress provided the Commission with specific anti-manipulation 

 413 EPAct 2005 expanded the Commission’s civil penalty authority under the FPA 

to encompass violations of all provisions of FPA Part II (EPAct 2005 section 1284(e)(1) 

(to be codified at section 316A of the FPA ,16 U.S.C. 825o-1)), and established the 

maximum civil penalty the Commission can assess under FPA Part II as $1 million per 

day per violation (EPAct 2005 section 1284(e)(2) (to be codified at section 316A of the 

FPA, 16 U.S.C. 825o-1)). 

414 Investigation of Terms and Conditions of Public Utility Market-Based Rate 

Authorizations, 105 FERC ¶ 61,218 (2003), order on reh’g, 107 FERC ¶ 61,175 (2004). 

415 NOI at P 15. 

416 Enforcement of Statutes, Order, Rules and Regulations, Policy Statement on 

Enforcement, 113 FERC ¶ 61,068 at P 17-20 (2005) (Enforcement Policy Statement). 
Docket Nos. RM05-25-000 and RM05-17-000 - 327 – 

authority.417 On January 19, 2006, to implement this new authority, the Commission 

issued Order No. 670 (Anti-manipulation Rule),418 adopting a new Part 1c of its 

regulations, under which it is “unlawful for any entity, directly or indirectly, in 

connection with the purchase or sale of electric energy or the purchase or sale of 

transmission services subject to the jurisdiction of the Commission, (1) to use or employ 

any device, scheme, or artifice to defraud, (2) to make any untrue statement of a material 

fact or to omit to state a material fact necessary in order to make the statements made, in 

the light of the circumstances under which they were made, not misleading, or (3) to 

engage in any act, practice, or course of business that operates or would operate as a 

fraud or deceit upon any entity.”419 The Anti-manipulation Rule made it unnecessary to 

retain Market Behavior Rules 2 or 6. Accordingly, on February 16, 2006, the 

 417 EPAct 2005 sec.1283 (to be codified at section 222 of the FPA, 16 U.S.C. 

824v). Congress prohibited the use or employment of “any manipulative or deceptive 

device or contrivance” in connection with the purchase or sale of electric energy or 

transmission services subject to the jurisdiction of the Commission. Congress directed 

the Commission to give these terms the same meaning as under the Securities Exchange 

Act of 1934, 15 U.S.C. 78j(b) (2000). 

418 Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 

(Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202, reh’g denied, 114 FERC ¶ 61,300 (2006). 

419 Id., 71 FR 4244, 4258 (Jan. 26, 2006) (to be codified at 18 CFR 1c.2(a)). 
Docket Nos. RM05-25-000 and RM05-17-000 - 328 – 

Commission rescinded Market Behavior Rules 2 and 6 and codified the substance of 

Market Behavior Rules 1, 3, 4, and 5 in the Commission’s regulations.420 

b. Whether Civil Penalties Should Be Specified in the OATT 

Comments

474. Commenters often did not distinguish between operational penalties and civil 

penalties in their comments about the need for additional penalties in the OATT. EEI and 

MidAmerican made the distinction, asserting that civil penalties should not be specified 

in the OATT. They and others contend that: enforcement actions, including civil 

penalties, should be reviewed on a case-by-case basis;421 civil penalties should be based 

upon the seriousness of the violation;422 penalties should require proof of intent or 

willfulness;423 penalties should only apply for repeated violations;424 and, penalty 

 420 Investigation of Terms and Conditions of Public Utility Market-Based Rate 

Authorizations, 114 FERC ¶ 61,165 (2005). The primary purpose of the Market 

Behavior Rules was to prohibit market manipulation by public utility sellers acting under 

market-based rate authority. 

421 E.g., Entergy, Santa Clara, Steel Manufacturers Association, WAPA, and 

Williams. 

422 Steel Manufacturers Association. 

423 E.g., EEI, KCP&L, Progress Energy, Public Power Council, Southern, and 

Xcel. 

424 E.g., Alberta Intervenors, Public Power Council, Snohomish, Suez Energy NA, 

and TDU Systems. 
Docket Nos. RM05-25-000 and RM05-17-000 - 329 – 

procedures should provide for due process.425

Discussion

475. The Commission intends to enforce OATT provisions in a firm but fair manner. 

For example, the Commission elsewhere is proposing that transmission providers as well 

as transmission customers be subject to specified operational penalties for violations of 

certain OATT provisions. However, aside from these operational penalties, the 

Commission does not intend to provide a schedule of enforcement remedies and 

sanctions in the OATT. Instead, the Commission prefers to examine violations and 

determine the appropriate response for a violation on a case-by-case basis. The 

Commission has a broad array of equitable remedies and sanctions for violations.426 Our 

enhanced civil penalties, as provided by EPAct 2005, are among the available sanctions 

for violations of the Commission’s statutes, rules, regulations and orders, including 

instances of undue discrimination and market manipulation. 

476. Although we will look at violations on a case-by-case basis and not identify in this 

proposed rule specific penalties for different violations, the Enforcement Policy 

Statement provides guidance and regulatory certainty regarding enforcement and places 

 425 E.g., Bonneville, EEI, Southern, and Nevada Companies. 

426 Enforcement Policy Statement at P 4. The “enhanced civil penalty authority 

will operate in tandem with our existing authority to require disgorgement of unjust 

profits obtained through misconduct and/or to condition, suspend, or revoke certificate 

authority or other authorizations, such as market-based rate authority for sellers of 

electric energy.” Id. at P 12. 
Docket Nos. RM05-25-000 and RM05-17-000 - 330 – 

entities subject to our jurisdiction on notice of the consequences of violations.427 As we 

noted, “[I]t is important that we retain the discretion and flexibility to address each case 

on its merits, and to fashion remedies appropriate to the facts presented, including any 

mitigating factors.”428 

477. As the facts of a specific matter warrant, we will seek disgorgement of unjust 

profits that are the result of a violation. Violators should not retain the gains acquired as 

the result of the violation. OATT violators will be expected to disgorge unjust profits 

whenever they can be determined or reasonably estimated.429 In addition, as warranted 

by the facts, civil penalties may also be assessed. Those penalties (up to $1 million per 

day per violation), however, can be mitigated by the factors set forth in the Enforcement 

Policy Statement, such as self-reporting, compliance programs, and cooperation with 

staff from the Commission’s Office of Enforcement.430 

 427 Id. at P 1. 

428 Id. at P 13. Several commenters supported the application of the Enforcement 

Policy Statement to OATT violations. E.g., APPA, EEI, Midwest SATs, National Grid, 

and TAPS. 

429 Enforcement Policy Statement at P 19 and P 23. 

430 Id. at P 6 and P 21-27. 
Docket Nos. RM05-25-000 and RM05-17-000 - 331 – 

c. Whether Transmission Providers Should Be Subject to 

Revocation of Their Market-Based Rates for OATT 

Violations. 

Comments

478. In the NOI, the Commission also asked if transmission providers should be subject 

to revocation of their market-based rate authority for certain OATT violations.431 Some 

commenters agree that revocation of market-based rates could be an appropriate 

remedy.432 EPSA asserts that revocation of market-based rate authority should be among 

the penalties the Commission could impose for serious violations of the OATT, such as 

when more transmission capacity is set aside than is actually needed to serve native load, 

or undue preferences are extended to native load or affiliate transactions. TAPS states 

that where lack of ATC forecloses network customer access to alternatives, a 

transmission provider should not be able to make sales of electric power at market-based 

rates and should be required to offer embedded-cost-based sales. APPA asserts that 

whether a transmission provider’s violation of the OATT merits possible revocation of its 

market-based rate authority depends on the nature and severity of the violation. APPA 

argues that if the violation concerns practices that favor the transmission provider’s own 

wholesale merchant function at the expense of its third-party competitors, and if that 

 431 NOI at P 15. 

432 E.g., Arkansas Cities, NRECA, Occidental, Snohomish, and Williams. 
Docket Nos. RM05-25-000 and RM05-17-000 - 332 – 

violation is willful or repeated, then revocation or conditioning of the market-based rate 

authority of the transmission provider’s merchant function may be warranted.433

479. Other commenters argue that revocation of market-based rate authority should be 

reserved for market behavior violations, not OATT violations.434 EEI and MidAmerican 

argue that the Commission has separated public utilities’ transmission functions from 

their marketing functions and, thus, penalties for violation of the OATT should be kept 

separate from penalties imposed for market behavior violations. PacifiCorp contends that 

the Commission’s new penalty authority is sufficient to ensure compliance with the 

OATT and that there no longer is a need to consider revocation of market-based rate 

authority. Progress Energy states that the Commission should not penalize the utility's 

merchant function for violations of the OATT caused by the utility's transmission 

function. Ameren and Southern would add a “willful” or “intent” requirement to 

revoking market-based rates for an OATT violation. 

Discussion 

480. As discussed in the Enforcement Policy Statement, the better approach is to look 

at all of the facts and circumstances of each violation before deciding on any remedy or 

 433 APPA at 32. 

434 E.g., EEI, MidAmerican, PacifiCorp, PNM-TNMP, and Progress Energy. 
Docket Nos. RM05-25-000 and RM05-17-000 - 333 – 

sanction.435 There may be OATT violations in circumstances that, after applying the 

factors in the Enforcement Policy Statement, merit revocation or limitation of marketbased rate authority. However, before the Commission will consider revoking an entity’s 

market-based rate authority for a violation of the OATT, there must be a nexus between 

the specific facts relating to the OATT violation and the entity’s market-based rate 

authority. The Commission proposes that if it determines, as a result of a significant 

OATT violation, that the market-based rate authority of a transmission provider will be 

revoked within a particular market, each affiliate of the transmission provider that 

possesses market-based rate authority will have it revoked in that market on the effective 

date of revocation of the transmission provider’s market-based rate authority. 

d. Whether Certain OATT Violations Should Be 

Considered Market Manipulation under the Market 

Behavior Rules and Section 1283 of EPAct 2005. 

Comments

481. In the NOI, the Commission asked if specific OATT violations should be 

considered market manipulation under the Market Behavior Rules and section 1283 of 

EPAct 2005.436 The Commission then suggested that one such type of violation might be 

when a transmission provider sets aside more transmission capacity than is needed to 

 435 Enforcement Policy Statement at P 18. Among the factors examined are 

“willfulness” and “intent” of the violator. Id. at P 20. 

436 NOI at P 15. Section 1283 of EPAct 2005 establishes section 222 of the FPA 

(to be codified at 16 U.S.C. 824v). 
Docket Nos. RM05-25-000 and RM05-17-000 - 334 – 

serve native load, but uses the capacity for third-party sales.437

482. None of the commenters want specific violations identified in the OATT to be 

deemed per se market manipulation. Some commenters prefer to have the Commission 

approach these matters on case-by-case basis.438

483. Some commenters, like Constellation, identify OATT violations that may 

constitute market manipulation. Ameren, EEI, and Occidental argue that intentionally 

setting aside more transmission capacity than is needed to serve native load could 

constitute market manipulation. LG&E states that the key factor is “intent.” LG&E 

provides an example in which ATC becomes available as a result of less-than-expected 

native load requirements, and not because the transmission owner intentionally overstated 

native load requirements, and the transmission owner’s affiliate followed proper 

reservation and scheduling protocol in a manner applicable to all potential transmission 

customers. Under these circumstances, LG&E contends, the Commission’s imposition of 

a civil penalty would be inappropriate given the absence of intent to impart false or 

misleading information into the marketplace or hoard transmission. 

484. Occidental suggests that curtailments of firm transmission service designed to 

permit wholesale power sales by the merchant function of the transmission provider or an 

affiliate should also be considered market manipulation. Suez Energy NA argues that 

 437 NOI at P 15. 

438 E.g., APPA, Entergy, Nevada Companies, Public Power Council, and Southern. 
Docket Nos. RM05-25-000 and RM05-17-000 - 335 – 

incidents of affiliate abuse by a transmission provider may be considered market 

manipulation pursuant to section 1283 of EPAct 2005. TAPS states that certain 

withholding of transmission capacity can rise to the level of a violation of the 

Commission’s market behavior rules and its new anti-manipulation authority if the 

withholding reduces the supply of both transmission and generation in a market, which 

artificially raises prices. 

Discussion

485. As explained above, we now are examining market manipulation in the context of 

Part 1c of our regulations. We do not propose to identify in the OATT specific conduct 

as per se market manipulation. As noted in Order No. 670, market manipulation is a factintensive determination.439 We do not want to restrict our fact-finding to specific types of 

violations. Although certain fraudulent or deceptive practices concerning the OATT 

could qualify as market manipulation under Order No. 670, the Commission declines to 

address such circumstances generically in this rulemaking and instead will consider them 

on a case-by-case basis, if and when they arise, under the standards set forth in Order 

No. 670. 

VI. Information Collection Statement

486. The following collections of information contained in this proposed rule have been 

submitted to the Office of Management and Budget (OMB) for review under section 

 439 Anti-manipulation Rule at P 72. 
Docket Nos. RM05-25-000 and RM05-17-000 - 336 – 

3507(d) of the Paperwork Reduction Act of 1995.440 OMB’s regulations require OMB to 

approve certain information collection requirements imposed by agency rule.441

487. Comments are solicited 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 techniques. 

 440 44 U.S.C. 3507(d) (2000). 

441 5 CFR 1320.11 (2005). 
Docket Nos. RM05-25-000 and RM05-17-000 - 337 – 

Burden Estimate: The public reporting and records retention burdens for the proposed 

reporting requirements and the records retention requirement are as follows.442 

Data 

Collection 

Number of 

Respondents 

Number of 

Responses 

Hours per 

Response 

Total Annual 

Hours 

Part 35 

(FERC-516) 

 

Conforming 

tariff changes 

176 1 25 4,400

Revision of 

Imbalance 

Charges 

176 1 5 880

ATC revisions 176 1 40 7,040

Planning 

(Attachment K) 

176 1 100 17,600

Congestion 

studies 

176 1 250 44,000

Attestation of 

network 

resource 

commitment 

176 1 1 176

Quarterly 

Reports for 

capacity 

reassignment 

176 1 60 10,560

Operational 

Penalty annual 

filing 

176 1 10 1,760

Creditworthines

s – include 

criteria in the 

tariff 

176 1 40 7,040

Sub Total Part 

35 

- - - 93,456

 442 These burden estimates apply only to this NOPR and do not reflect upon all of 

FERC-516 or FERC-717. 
Docket Nos. RM05-25-000 and RM05-17-000 - 338 – 

Part 37 

(FERC-717) 

ATC-related 

standards: 

 

NERC/NAESB 

Team to 

develop 

 Review and 

comment by 

utility 

 

Implementation 

by each utility 

1

176

176

1

1

1

1,920 

20 

40 

1,920

3,520

7,040

Mandatory data 

exchanges 

176 1 80 14,080

Explanation of 

change of ATC 

values 

176 1 100 17,600

Reevaluate 

CBM and post 

quarterly 

176 1 20 3,520

Post OASIS 

metrics; 

requests 

accepted/denied 

176 1 80 14,080

Posting of 

metrics for 

System Impact 

Studies 

176 1 100 17,600

Post all rules to 

OASIS 

176 1 5 880

 Sub Total 

(Part 37) 

- - - 80,240

Total (Part 35 + 

Part 37) 

- - - 173,696

Recordkeeping 176 1 30 5,280
Docket Nos. RM05-25-000 and RM05-17-000 - 339 – 

Total Annual Hours for Collection: 

Reporting + recordkeeping hours = 173,696 + 5,280 = 178,976 hours. 

Cost to Comply: 

Reporting = $19,801,344 

173,696 hours @ $114 an hour (average cost of attorney ($200 per hour), 

consultant ($150), technical ($80), and administrative support ($25)) 

Recordkeeping = $1,392,160 

Labor (file/record clerk @ $17 an hour) 5,280 hours @$17/hour = $89,760 

Storage 176 respondents@8,000 sq. ft. x $925 (off site storage) = $1,302,400 

Total costs = $21,193,504 

Labor $ ($19,801,344 + $89,760) + Recordkeeping Storage Costs ($1,302,400) 

OMB’s regulations require it to approve certain information collection requirements 

imposed by an agency rule. The Commission is submitting notification of this proposed 

rule to OMB. If the proposed requirements are adopted they will be mandatory 

requirements. 

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: 

488. The Federal Energy Regulatory Commission is proposing amendments to its 
Docket Nos. RM05-25-000 and RM05-17-000 - 340 – 

regulations adopted in Order Nos. 888 and 889, and to the pro forma open access 

transmission tariff, to ensure that transmission services are provided on a basis that is 

just, reasonable and not unduly discriminatory or preferential. The purpose of this 

rulemaking is to strengthen the pro forma OATT to ensure that it achieves its original 

purpose – remedying undue discrimination – not to create new market structures. We 

propose to achieve this goal by increasing the clarity and transparency of the rules 

applicable to the planning and use of the transmission system and by addressing 

ambiguities and the lack of sufficient detail in several important areas of the pro forma

OATT. The lack of specificity in the pro forma OATT creates opportunities for undue 

discrimination as well as making the undue discrimination that does occur more difficult 

to detect. To accomplish this we are proposing five objectives: (1) to improve 

transparency and consistency in several critical areas, by providing for greater 

consistency in the calculation of ATC, (2) to reform the transmission planning 

requirements of the pro forma OATT to eliminate potential undue discrimination and 

support the construction of adequate transmission facilities to meet the needs of all loadserving entities, (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 
Docket Nos. RM05-25-000 and RM05-17-000 - 341 – 

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 NOPR 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. 

489. 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.] 

490. 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)395-4650, 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

491. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 
Docket Nos. RM05-25-000 and RM05-17-000 - 342 – 

on the human environment.443 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this NOPR under 

section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale subject to 

the Commission’s jurisdiction, plus the classification, practices, contracts and regulations 

that affect rates, charges, classifications and services.444

VIII. Regulatory Flexibility Act Analysis 

492. The Regulatory Flexibility Act of 1980 (RFA)445 generally requires a description 

and analysis of proposed 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, not to electric utilities per se. The total number of public 

utilities that, absent waiver, would have to modify their current OATTs by filing the 

revised pro forma OATT is 176.446 Of these only six public utilities, or less than two 

 443 Regulations Implementing the National Environmental Policy Act, Order No. 

486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). 

444 18 CFR 380.4(a)(15) (2005). 

445 5 U.S.C. 601-612 (2000). 

446 The sources for this figure are FERC Form No. 1 and FERC Form No. 1-F 

data. 
Docket Nos. RM05-25-000 and RM05-17-000 - 343 – 

percent, dispose of four million MWh or less per year.447 The Commission does not 

consider this a substantial number, and in any event, these small entities may seek waiver 

of these requirements.448 Moreover, the criteria for waiver that would be applied under 

this rulemaking for small entities is unchanged from that used to evaluate requests for 

waiver under Order Nos. 888 and 889. Thus, small entities who have received waiver of 

the requirements to have on file an open access tariff or to operate an OASIS would be 

unaffected by the requirements of this proposed rulemaking. 

IX. Comment Procedures

493. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due [insert date 60 days 

from publication in the FEDERAL REGISTER]. Reply comments are due [insert date 

 447 Id.

448 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)(2000); 15 U.S.C. 632(a)(1) (2000). In Mid-Tex Elec. 

Coop. v. FERC, 773 F.2d 327, 340-343 (D.C. Cir. 1985), the court accepted the 

Commission's conclusion that, since virtually all of the public utilities that it regulates do 

not fall within the meaning of the term "small entities" as defined in the Regulatory 

Flexibility Act, the Commission did not need to prepare a regulatory flexibility analysis 

in connection with its proposed rule governing the allocation of costs for construction 

work in progress (CWIP). The CWIP rules applied to all public utilities. The revised pro 

forma OATT will apply only to those public utilities that own, control or operate 

interstate transmission facilities. These entities are a subset of the group of public 

utilities found not to require preparation of a regulatory flexibility analysis for the CWIP 

rule. 
Docket Nos. RM05-25-000 and RM05-17-000 - 344 – 

30 days from the date initial comments are submitted]. Comments must refer to Docket 

Nos. RM05-25-000 and RM05-17-000, and must include the commenters’ name, the 

organization they represent, if applicable, and their address in their comments. 

Comments may be filed either in electronic or paper format. 

494. To facilitate the Commission’s review of the comments, commenters are requested 

to provide an executive summary of their position, not to exceed ten pages. Commenters 

are requested to identify each section of the NOPR that their discussion addresses and to 

use conforming headings. Additional issues the commenters wish to raise should be 

clearly identified in a separate section entitled “Other Issues,” which should be organized 

by the relevant pro forma OATT section (if applicable). Furthermore, we also request 

that commenters with specific tariff language suggestions submit a redline/strikeout 

version showing their proposed changes to the language that appears in the pro forma

OATT attached to this NOPR.449 The commenters should double space their comments. 

To assist commenters in their review, the Commission has posted a copy of the proposed 

revised pro forma OATT with changes from the current version of the pro forma OATT 

 449 The pro forma OATT includes two amendments that have been made since the 

tariff was finalized in Order No. 888-B. First, the tariff was amended to include 

protocols for curtailment of multi-system transactions and parallel flows. See North 

American Reliability Council, 85 FERC ¶ 61,353 (1998), reh’g denied, 87 FERC ¶ 

61,161 (1999) and recently updated in North American Electric Reliability Council, 

110 FERC ¶ 61,388 (2005). The second amendment incorporates standardized generator 

interconnection procedures. See Order No. 2003. The standardized generator 

interconnection procedures are not included in the pro forma OATT attached to this 

NOPR because we do not propose changes to them. 
Docket Nos. RM05-25-000 and RM05-17-000 - 345 – 

shown in redline/strikeout on the following location on our website at 

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

495. Comments and reply comments may be filed electronically via the eFiling link on 

the Commission's web site at http://www.ferc.gov. The Commission accepts most 

standard word processing formats and commenters may attach additional files with 

supporting information in certain other file formats. Documents created electronically 

using word processing software should be filed in the native application or print-to-PDF 

format and not in a scanned format. This will enhance document retrieval for both the 

Commission and the public. Attachments that exist only in paper form may be scanned. 

Commenters filing electronically should not make a paper filing. Service of rulemaking 

comments is not required. Commenters that are not able to file comments electronically 

must send an original and 14 copies of their comments to: Federal Energy Regulatory 

Commission, Office of the Secretary, 888 First Street N.E., Washington, DC, 20426. 

496. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 

X. Document Availability

497. 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 346 – 

(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. 

498. From the Commission’s Home Page on the Internet, this information is available 

in the Commission’s document management system, eLibrary. The full text of this 

document is available on eLibrary in PDF and Microsoft Word format for viewing, 

printing, and/or downloading. To access this document in eLibrary, type “RM05-25” or 

“RM05-17” in the docket number field. 

499. 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). 

List of Subjects 

18 CFR Part 35 

Electric power rates, Electric utilities, Reporting and recordkeeping requirements 
Docket Nos. RM05-25-000 and RM05-17-000 - 347 – 

18 CFR Part 37

 Conflict of interests, Electric power plants, Electric utilities, Reporting and 

recordkeeping requirements 

By direction of the Commission. 

( S E A L ) 

 Magalie R. Salas, 

 Secretary.
Docket Nos. RM05-25-000 and RM05-17-000 - 348 – 

 
Docket Nos. RM05-25-000 and RM05-17-000 - 349 – 

 In consideration of the foregoing, the Commission proposes to amend 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 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, as revised by the open access 

pro forma tariff contained in Order No. _____, FERC Stats. & Regs. ¶ ___, or such other 
Docket Nos. RM05-25-000 and RM05-17-000 - 350 – 

open access tariff as may be approved by the Commission consistent with Order No. 

_____, 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. 

_____, 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 ____, it must file the 

revisions to the pro forma tariff contained in Order No. ___, FERC Stats. & Regs. ¶ ____, 

pursuant to section 206 of the FPA and accompanying rates pursuant to section 205 of the 

FPA, no later than ____. 

(iii) If a public utility owns, controls, or operates transmission facilities used for 

the transmission of electric energy in interstate commerce as of _____, such facilities are 

jointly owned with a non-public utility, and the joint ownership contract prohibits 

transmission service over the facilities to third parties, the public utility with respect to 

access over the public utility's share of the jointly owned facilities must file no later than 

________ the revisions to the pro forma tariff contained in Order No. ____, FERC Stats. 

& Regs. ¶ ____, pursuant to section 206 of the FPA and accompanying rates pursuant to 
Docket Nos. RM05-25-000 and RM05-17-000 - 351 – 

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. _____, FERC 

Stats. & Regs. ¶ _____, must demonstrate that the deviation is consistent with the 

principles of Order No. ____, 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 

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 tariff filed pursuant to this section. 
Docket Nos. RM05-25-000 and RM05-17-000 - 352 – 

 (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 pro forma tariff, which tariff must be 

the open access 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. _____, 

FERC Stats. & Regs. ¶ ___, or such other open access tariff as may be approved by the 

Commission consistent with Order No. _____, FERC Stats. & Regs. ¶ _____. 

 (i) For any power pool, public utility holding company or other multi-lateral 

arrangement or agreement that contains transmission rates, terms or conditions and that is 

executed after July 9, 1996, this requirement is effective on the date that transactions 
Docket Nos. RM05-25-000 and RM05-17-000 - 353 – 

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 July 9, 1996, 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. ___, FERC Stats. & Regs. ¶ ____, pursuant to section 206 of the FPA and 

accompanying rates pursuant to section 205 of the FPA, no later than ____. 

 (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 pro forma 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 

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, as revised by the open access pro forma tariff contained in Order 

No. _____, FERC Stats. & Regs. ¶ ___, or such other open access tariff as may be 
Docket Nos. RM05-25-000 and RM05-17-000 - 354 – 

approved by the Commission consistent with Order No. _____, 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. ___, FERC 

Stats. & Regs. ¶ ____, pursuant to section 206 of the FPA and accompanying rates 

pursuant to section 205 of the FPA, no later than ____. 

(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. ___, 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 no later than ____. 

(d) Waivers. * * * 

 (1) No later than ______, or 

 (2) * * * 

* * * * * 

 (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. ____, FERC Stats. & Regs. ¶ 

_____. 

 (i) * * * 
Docket Nos. RM05-25-000 and RM05-17-000 - 355 – 

 (ii) If the submittal is found to be an acceptable transmission tariff, an applicant in 

a Federal Power Act (FPA) section 211 or 211A proceeding against the non-public utility 

shall have the burden of proof to show why service under the open access tariff is not 

sufficient and why a section 211 or 211A order should be granted. 

* * * * * 

PART 37—OPEN ACCESS SAME-TIME INFORMATION SYSTEMS 

3. The authority citation for part 37 continues to read as follows: 

Authority: 16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-

7352. 

4. Amend § 37.6 as follows: 

a. paragraph (a)(1) is revised. 

b. paragraph (b)(introductory text) is revised. 

c. paragraphs (b)(1)(v) through (b)(1)(viii) are added. 

d. paragraphs (b)(2)(i) and b(2)(ii) are revised. 

e. paragraph (b)(3) is revised. 

f. paragraph (c)(2) is revised. 

g. paragraphs (e)(1) and (e)(2)(ii) are revised. 

h. paragraph (e)(3)(ii) is revised. 

i. paragraphs (h) and (i) are added. 

§ 37.6 Information to be posted on the OASIS. 
Docket Nos. RM05-25-000 and RM05-17-000 - 356 – 

 (a) * * * 

 (1) Make requests for transmission services offered by Transmission Providers, 

Resellers and other providers of ancillary services, request the designation of a network 

resource, and request the termination of the designation of a network resource; 

* * * * * 

 (b) Posting transfer capability. The available transfer capability on the 

Transmission Provider’s system (ATC) and the total transfer capability (TTC) of that 

system shall be calculated and posted for each Posted Path as set out in this section. 

 (1) * * * 

 (v) Available transfer capability or ATC means the transfer capability 

remaining in the physical transmission network for further commercial activity over and 

above already committed uses, or such definition as contained in Commission-approved 

Reliability Standards. 

 (vi) Total transfer capability or TTC means the amount of electric power that 

can be moved or transferred reliably from one area to another area of the interconnected 

transmission systems by way of all transmission lines (or paths) between those areas 

under specified system conditions, or such definition as contained in 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 357 – 

generation from interconnected systems to meet generation reliability requirements, or 

such definition as contained in Commission-approved Reliability Standards. 

(viii) Transmission Reliability Margin or TRM means the amount of TTC 

necessary to provide reasonable assurance that the interconnected transmission network 

will be secure, or such definition as contained in Commission-approved Reliability 

Standards. 

 (2) * * * 

 (i) Information used to calculate any posting of ATC and TTC must be dated 

and time-stamped and all calculations shall be performed according to consistently 

applied methodologies referenced in the Transmission Provider's transmission tariff and 

shall be based on Commission-approved Reliability Standards as well as current industry 

practices, standards and criteria 

(ii) On request, the Responsible Party must make all data used to calculate 

ATC, TTC, CBM, and TRM for any constrained posted paths publicly available 

(including the limiting element(s) and the cause of the limit (e.g., thermal, voltage, 

stability)) 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. 

* * * * * 

(3) Posting. The ATC, TTC, CBM, and TRM for all Posted Paths must be 
Docket Nos. RM05-25-000 and RM05-17-000 - 358 – 

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. 

 (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 TTC 

estimate for the Path changes by more than 10 percent. 
Docket Nos. RM05-25-000 and RM05-17-000 - 359 – 

 (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) are updated, the Transmission Provider shall post a brief, but 

specific, narrative explanation of the reason for the update. This narrative should include, 

if relevant, scheduling of planned outages and occurrence of forced transmission outages, 

de-ratings of transmission facilities, scheduling of planned generation outages and 

occurrence of forced generation outages, changes in load forecast, changes in new 

facilities’ in-service dates, or other events or assumption changes that caused the update. 

(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. 
Docket Nos. RM05-25-000 and RM05-17-000 - 360 – 

(A) The Transmission Provider must reevaluate its CBM needs at least 

quarterly. 

(B) The Transmission Provider must post its practices for reevaluating its CBM 

needs. 

(c) Posting Transmission Service Products and Prices. 

(1) * * * 

 (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 post all of their rules, standards and practices that 

relate to transmission services. 

* * * * * 

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

conducted in accordance with the Transmission Provider's tariff, the Federal Power Act, 

and Commission regulations. 

(ii) The requirement in paragraph (e)(1)(i) of this section, to post requests for 

transmission and ancillary service offered by Transmission Providers under the pro forma

tariff, including requests for discounts, prior to the Transmission Provider responding to 

the request, does not apply to requests for next-hour service made during Phase I. 

(iii) In the event that a discount is being requested for ancillary services that are 

not in support of basic transmission service provided by the Transmission Provider, such 

request need not be posted on the OASIS. 

(iv) In processing a request for transmission or ancillary service, the 

Responsible Party shall post the same information as required in paragraphs (c)(4) and 

(d)(3) of this section, and the following information: the date and time when the request 

is made, its place in any queue, the status of that request, and the result (accepted, denied, 

withdrawn). In processing a request to designate or terminate the designation of a 

network resource, the Responsible Party shall post the date and time when the request is 

made. 

(v) For any request to designate or terminate a network resource, the 

Transmission Provider (at the time when the request is received), must post on the 

OASIS (and make available for download) information describing the request (including: 

name of requestor, identification of the resource, effective time for the designation or 

termination, identification of whether the transaction involves the Transmission 
Docket Nos. RM05-25-000 and RM05-17-000 - 362 – 

Provider’s wholesale merchant function or any affiliate; and any other relevant terms and 

conditions) and shall keep such information posted on the OASIS for at least 30 days. A 

record of the transaction must be retained and kept available as part of the audit log 

required in § 37.7. 

(vi) The Transmission Provider shall post a list of its current designated 

network resources and all network customers’ current designated network resources on 

OASIS. The list of network resources should include the name of the resource, its 

geographic and electrical location, its total installed capacity, and the amount of capacity 

to be designated as a network resource. 

(2) * * * 

(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. 

* * * * * 

(3) Posting when a transaction is curtailed or interrupted. 

(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 
Docket Nos. RM05-25-000 and RM05-17-000 - 363 – 

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 

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 
Docket Nos. RM05-25-000 and RM05-17-000 - 364 – 

during the reporting quarter, from the date when the Responsible Party received the 

request for transmission service to when the Responsible Party changed the transmission 

service request status to indicate that the Responsible Party could offer transmission 

service or needed to perform a system impact study,

(D) Mean time (in days), for all system impact study agreements delivered by 

the Responsible Party during the reporting quarter, from the date when the Responsible 

Party received the request for transmission service to the date when the Responsible Party 

delivered a system impact study agreement, and 

(E) Number of new system impact study agreements executed during the 

reporting quarter.

(ii) System Impact Study Processing Time. 

(A) Number of system impact studies completed by the Responsible Party 

during the reporting quarter, 

(B) Number of system impact studies completed by the Responsible Party 

during the reporting quarter more than 60 days after the Responsible Party received an 

executed system impact study agreement, 

(C) 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 365 – 

(D) Mean cost of system impact studies completed by the Responsible Party 

during the reporting quarter. 

(iii) Transmission Service Requests Withdrawn from the System Impact Study 

Queue. 

(A) Number of transmission service requests withdrawn from the Responsible 

Party’s system impact study queue during the reporting quarter, 

(B) Number of transmission service requests withdrawn from the Responsible 

Party’s system impact study queue during the reporting quarter more than 60 days after 

the Responsible Party received the executed system impact study agreement, and 

(C) Mean time (in days), for all transmission service requests withdrawn 

from the Responsible Party’s system impact study queue during the reporting quarter, 

from the date the Responsible Party received the executed system impact study 

agreement to date when request was withdrawn from the Responsible Party’s system 

impact study queue. 

(iv) Process Time from Completed System Impact Study to Offer of Facilities 

Study. 

(A) Number of new facilities study agreements delivered during the reporting 

quarter to entities that request transmission service, 

(B) Number of new facilities study agreements delivered during the reporting 

quarter to entities that request transmission service more than thirty (30) days after the 

Responsible Party completed the system impact study, 
Docket Nos. RM05-25-000 and RM05-17-000 - 366 – 

(C) Mean time (in days), for all facilities study agreements delivered by the 

Responsible Party during the reporting quarter, from the date when the Responsible Party 

completed the system impact study to the date when the Responsible Party delivered a 

facilities study agreement, and 

(D) Number of new facilities study agreements executed during the reporting 

quarter. 

 (v) Facilities Study Processing Time. 

(A) Number of facilities studies completed by the Responsible Party during 

the reporting quarter, 

(B) Number of facilities studies completed by the Responsible Party during 

the reporting quarter more than 60 days after the Responsible Party received an executed 

facilities study agreement, 

(C) 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, 

(D) Mean cost of facilities studies completed by the Responsible Party during 

the reporting quarter, and 

(E) Mean cost of upgrades recommended in facilities studies completed 

during the reporting quarter. 

(vi) Service Requests Withdrawn from Facilities Study Queue. 
Docket Nos. RM05-25-000 and RM05-17-000 - 367 – 

(A) Number of transmission service requests withdrawn from the Responsible 

Party’s facilities study queue during the reporting quarter, 

(B) Number of transmission service requests withdrawn from the 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 
Docket Nos. RM05-25-000 and RM05-17-000 - 368 – 

has received the appropriate executed study agreement. For the purposes of calculating 

the percent of studies completed more than sixty (60) days after the Responsible Party 

delivers the appropriate study agreement, the Responsible Party should aggregate all 

system impact studies and facilities studies that it completes during the reporting quarter. 

The Responsible Party must calculate and post the measures in paragraph (h)(3)(i) 

through paragraph (h)(3)(iv) of this section separately for requests for short-term firm 

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

 (4) The Responsible Party is required to post the measures in paragraph 

(h)(3)(a) through paragraph (h)(3)(d) of this section for each calendar quarter within 15 

days of the end of the calendar quarter. The Responsible Party will keep the quarterly 

measures posted on OASIS for five calendar years. 

(i) Posting data related to grants and denials of service. The Responsible Party 

is required to post data each month listing, by path or flowgate, the number of 

transmission service requests that have been accepted and the number of transmission 

service requests that have been denied during the prior month. This posting must 

distinguish between the length of the service request (e.g., short-term or long-term 

requests) and between the type of service requested (e.g., firm point-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. 

5. In §37.7, paragraph (b) is revised to read as follows: 
Docket Nos. RM05-25-000 and RM05-17-000 - 370 – 

§ 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. RM05-25-000 and RM05-17-000 - 371 – 

NOTE: The following appendices will not be published in the Code of Federal 

Regulations. 

Appendix A: Commenter Acronyms

Initial Commenters in Docket No. RM05-25-000 

Abbreviation RM05-25-000 Initial Comments 

AEP American Electric Power System (AEP Texas North 

Company; AEP Texas Central Company; 

Appalachian Power Company; Columbus Southern 

Power Company; Indiana Michigan Power Company; 

Kentucky Power Company; Kingsport Power 

Company; Ohio Power Company; Public Service 

Company of Oklahoma; Southwestern Electric Power 

Company and Wheeling Power Company) 

Alabama MEA Alabama Municipal Electric Authority 

Alberta Intervenors Alberta Intervenors (TransCanada Energy Ltd.; 

ENMAX Energy Marketing, Inc.; EPCOR Merchant 

and Capital, LP; and TransAlta Corporation) 

Alberta System Operator Alberta Electric System Operator 

Alcoa Alcoa Inc. and Alcoa Power Generating Inc. 

Alliance of State Leaders Alliance of State Leaders Protecting Electricity 

Consumers 
Docket Nos. RM05-25-000 and RM05-17-000 - 372 – 

Abbreviation RM05-25-000 Initial Comments 

Ameren Ameren Services Company (Central Illinois Light 

Company d/b/a AmerenCILCO; Central Illinois 

Public Service Company d/b/a AmerenCIPS; Illinois 

Power Company d/b/a AmerenIP; Union Electric 

Company d/b/a AmerenUE; Ameren Energy 

Marketing Company; Ameren Energy Generating 

Company; and AmerenEnergy Resources Generating 

Company) 

American Forest and 

Paper*450

American Forest and Paper Association 

American Transmission American Transmission Company LLC 

AMP- Ohio American Municipal Power-Ohio, Inc. 

APPA American Public Power Association 

APS Arizona Public Service Company 

Arkansas Cities Arkansas Cities and Cooperative (Conway 

Corporation; West Memphis Utilities Commission; 

City of Osceola, Arkansas; City of Prescott, 

Arkansas; Hope Water & Light Commission; and 

Farmers Electric Cooperative Cooperation) 

Arkansas Commission Arkansas Public Service Commission 

AWEA American Wind Energy Association 

BC Transmission British Columbia Transmission Corporation 

Bonneville Bonneville Power Administration 

Bureau of Reclamation US Bureau of Reclamation 

CAISO California Independent System Operator Corporation 

California Commission Public Utilities Commission of the State of California 

Calpine Calpine Corporation 

 450 A “*” indicates that the commenter filed a notice of intervention only. 
Docket Nos. RM05-25-000 and RM05-17-000 - 373 – 

Abbreviation RM05-25-000 Initial Comments 

Canadian Electricity 

Association 

Canadian Electricity Association 

Chelan Public Utility District No. 1 of Chelan County and 

Public Utility District No. 2 of Grant County 

Cinergy Cinergy Services, Inc. (Cincinatti Gas & Electric 

Company; PSI Energy, Inc.; and Union Light, Heat 

and Power Company) 

Constellation Constellation Energy Group, Inc. 

Cottonwood Cottonwood Energy Company LP and Union Power 

Partners, LP 

Detroit Edison Detroit Edison Company 

Douglas Public Utility District No. 1 of Douglas County 

Duke Duke Energy Corporation 

East Texas Cooperatives East Texas Electric Cooperative, Inc.; Northeast 

Texas Electric Cooperative, Inc.; Sam Rayburn 

Generation and Electric Cooperative, Inc.; and TexLa Electric Cooperative of Texas, Inc. 

Edison Mission Edison Mission Energy, Edison Mission Marketing & 

Trading, Inc. and Midwest Generation EME, LLC 

EEI Edison Electric Institute 

ELCON Electricity Consumers Resource Council, American 

Iron and Steel Institute and American Chemistry 

Council 

Entergy Entergy Services, Inc. 

EPSA Electric Power Supply Association 

Exelon Exelon Corporation 
Docket Nos. RM05-25-000 and RM05-17-000 - 374 – 

Abbreviation RM05-25-000 Initial Comments 

Fayetteville Public Works Commission of the City of Fayetteville, 

North Carolina 

FirstEnergy FirstEnergy Service Company (FirstEnergy 

Solutions; American Transmission Systems, Inc.; 

Jersey Central Power and Light Company; 

Metropolitan Edison Company; and Pennsylvania 

Electric Company) 

Florida Industrial 

Cogeneration Association 

Florida Industrial Cogeneration Association 

FMPA Florida Municipal Power Agency 

FP&L Florida Power & Light Company 

Hogan William H. Hogan 

HQ Energy HQ Energy Services (US), Inc. 

IECG* Industrial Energy Consumer Group 

Indicated New York 

Transmission Owners 

Indicated New York Transmission Owners (Central 

Hudson Gas & Electric Corp.; Consolidated Edison 

Company of New York, Inc.; New York State 

Electric & Gas Corp.; Orange and Rockland Utilities, 

Inc.; LIPA; New York Power Authority; and 

Rochester Gas and Electric Corp.) 

International 

Transmission 

International Transmission Company 

ISO New England ISO New England, Inc. and New England Power Pool

ISO/RTO ISO/RTO Council 

KCP&L Kansas City Power & Light Company 

Kentucky Commission Kentucky Public Service Commission 
Docket Nos. RM05-25-000 and RM05-17-000 - 375 – 

Abbreviation RM05-25-000 Initial Comments 

Lafayette Lafayette Utilities System of the City and Parish of 

Lafayette, Louisiana; Mississippi Delta Energy 

Agency, Clarksdale Public Utilities Commission of 

the City of Clarksdale, Mississippi; and Public 

Service Commission of the City of Yazoo City, 

Mississippi 

LDWP City of Los Angeles Department of Water and Power 

LG&E LG&E Energy LLC (Louisville Gas and Electric 

Company and Kentucky Utilities Company) 

LPPC Large Public Power Council 

MEAG MEAG Power 

Memphis Light Memphis Light, Gas & Water Division 

Metropolitan Water 

District 

Metropolitan Water District of Southern California 

MidAmerican MidAmerican Energy Company 

Midwest Municipals Midwest Municipal Transmission Group 

Midwest SATs Midwest Stand-Alone Transmission Companies 

(American Transmission Company LLC; 

International Transmission Company; and Michigan 

Electric Transmission Company, LLC) 

MISO Midwest Independent Transmission System Operator, 

Inc. 

MISO States Organization of MISO States 

Montana Alberta Tie Montana Alberta Tie Ltd. 

NARUC National Association of Regulatory Utility 

Commissioners 

National Grid National Grid USA 

NCPA Northern California Power Agency 

Nevada Commission Public Utilities Commission of Nevada 
Docket Nos. RM05-25-000 and RM05-17-000 - 376 – 

Abbreviation RM05-25-000 Initial Comments 

Nevada Companies Nevada Power Company and Sierra Pacific Power 

Company 

New York Commission New York State Public Service Commission 

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 

Northeast Utilities Northeast Utilities Service Company (Connecticut 

Light and Power Company; Western Massachusetts 

Electric Company; Public Service Company of New 

Hampshire; Holyoke Water Power Company; and 

Holyoke Power and Electric Company) 

Northwest IPPs Northwest Independent Power Producers Coalition 

(BP Energy; Calpine Corporation; EPCOR; National 

Energy Supply Company; Northwest Energy 

Development; Sempra Generation; Suez Energy 

North America, Inc.; and TransAlta Energy 

Marketing, (U.S.) Inc.) 

Northwest Unregulated 

TUs 

Northwest Unregulated Transmitting Utilities (Clark 

Public Utilities; Public Utility District No. 1 of 

Cowlitz County; Eugene Water and Electric Board; 

Public Utility District No. 2 of Grant County; Public 

Utility District No. 1 of Snohomish County; and 

Tacoma Power) 

NorthWestern NorthWestern Corporation 

NPPD Nebraska Public Power District 

NRECA National Rural Electric Cooperative Association 

Occidental Occidental Chemical Corporation 

Ohio Commission Public Utilities Commission of Ohio 

Oklahoma Commission Oklahoma Corporation Commission 

Old Dominion Old Dominion Electric Cooperative 
Docket Nos. RM05-25-000 and RM05-17-000 - 377 – 

Abbreviation RM05-25-000 Initial Comments 

PacifiCorp PacifiCorp 

PJM PJM Interconnection, L.L.C. 

PNM-TNMP Public Service Company of New Mexico and TexasNew Mexico Power Company 

Portland General Portland General Electric Company 

Powerex Powerex Corp. 

PPL PPL Companies (PPL Electric Utilities Corporation; 

PPL EnergyPlus, LLC; PPL Montana, LLC; PPL 

Holtwood, LLC; Lower Mount Bethel Energy, LLC; 

PPL Maine, LLC; PPL Great Works, LLC; PPL 

Colstrip I, LLC; PPL Colstrip II, LLC; PPL Martins 

Creek, LLC; PPL Brunner Island, LLC; PPL 

Montour, LLC; PPL Susquehanna, LLC; PPL 

Wallingford Energy, LLC; PPL Southwest 

Generation Holdings, LLC; PPL University Park, 

LLC, PPL Shoreham Energy, LLC; and PPL 

Edgewood Energy, LLC) 

Progress Energy Progress Energy, Inc. (Carolina Power & Light 

Company d/b/a Progress Energy Carolinas and 

Florida Power Corporation, d/b/a Progress Energy 

Florida) 

Public Power Council Public Power Council 

Renewable Energy Renewable Energy and Public Interest Organizations 

(American Wind Energy Association; Citizens for 

Pennsylvania’s Future (PennFuture); Minnesotans for 

an Energy Efficient Economy; Natural Resources 

Defense Council; Ohio Consumers’ Council; Pace 

Energy Project; Project for Sustainable FERC Energy 

Policy; Renewable Northwest Project; The Stella 

Group, Ltd.; The Wind Coalition; and West Wind 

Wires) 

Rural Utilities Service US Department of Agriculture Rural Utilities Service 
Docket Nos. RM05-25-000 and RM05-17-000 - 378 – 

Abbreviation RM05-25-000 Initial Comments 

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 

Sempra Global Sempra Global 

SEPA Southeastern Power Administration 

Snohomish Public Utility District No. 1 of Snohomish County, 

Washington 

South Carolina E&G South Carolina Electric & Gas Company 

Southern Southern Company Services, Inc. 

Southern Montana Coop Southern Montana Electric Generation and 

Transmission Cooperative, Inc. 

Southwest TDU Group Southwest Transmission Dependent Utility Group 

(Aguila Irrigation District; Ak-Chin Energy Services; 

Buckeye Water Conservation and Drainage District; 

Central Arizona Water Conservation District; 

Electrical District No. 3; Electrical District No. 4; 

Electrical District No. 5; Electrical District No. 6; 

Electrical District No. 7; Electrical District No. 8; 

Harquahala Valley Power District; Maricopa County 

Municipal Water District No. 1; McMullen Valley 

Water Conservation and Drainage District; City of 

Needles; Roosevelt Irrigation District; City of 

Safford; Tonopah Irrigation District; WelltonMohawk Irrigation and Drainage District) 

Southwestern Coop Southwestern Electric Cooperative, Inc. 

SPP Southwest Power Pool, Inc. 

Steel Manufacturers 

Association 

Steel Manufacturers Association 
Docket Nos. RM05-25-000 and RM05-17-000 - 379 – 

Abbreviation RM05-25-000 Initial Comments 

Suez Energy NA Suez Energy North America 

Tacoma Tacoma Power 

TANC Transmission Agency of Northern California 

TAPS Transmission Access Policy Study Group 

TDU Systems Transmission Dependent Utilities Systems 

Tennessee Valley PPA Tennessee Valley Public Power Association 

TransAlta TransAlta Energy Marketing (US) Inc. 

Trans-Elect Trans-Elect, Inc. 

TVA Tennessee Valley Authority 

WAPA Western Area Power Administration 

Williams Williams Power Company, Inc. 

Wisconsin Commission Public Service Commission of Wisconsin 

Wisconsin Electric Wisconsin Electric Power Company 

Wyoming Infrastructure* Wyoming Infrastructure Authority 

Xcel Xcel Energy Services, Inc. 
Docket Nos. RM05-25-000 and RM05-17-000 - 380 – 

Reply Commenters in Docket No. RM05-25-000 

Abbreviation RM05-25-000 Reply Comments 

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 

BC Transmission British Columbia Transmission Corporation 

Bonneville Bonneville Power Administration 

California Municipal 

Utilities Association 

California Municipal Utilities Association 

Cogeneration 

Association of California 

Cogeneration Association of California and Energy 

Producers and Users Coalition 

EEI Edison Electric Institute 

ElectriCities ElectriCities of North Carolina, Inc. 

Entergy Entergy Services, Inc. 

EPSA Electric Power Supply Association 

Fallon City of Fallon, Nevada 

Fertilizer Institute Fertilizer Institute 

FMPA Florida Municipal Power Agency 

FP&L Florida Power & Light Company 

Great Northern Great Northern Power Development, L.P. 
Docket Nos. RM05-25-000 and RM05-17-000 - 381 – 

Abbreviation RM05-25-000 Reply Comments 

Joint Commenters Joint Commenters (Duke Energy Corporation, 

Progress Energy Corporation, South Carolina Public 

Service Authority and Southern Company Services, 

Inc.) 

Lafayette+451 Lafayette Utilities System of the City and Parish of 

Lafayette, Louisiana; Mississippi Delta Energy 

Agency, Clarksdale Public Utilities Commission of the 

City of Clarksdale, Mississippi; and Public Service 

Commission of the City of Yazoo City, Mississippi 

LDWP City of Los Angeles Department of Water and Power 

LPPC Large Public Power Council 

Mark Lively+ Mark B. Lively 

MEAG MEAG Power 

Memphis Light Memphis Light, Gas & Water Division 

Midwest Municipals Midwest Municipal Transmission Group 

Midwest SATs Midwest Stand-Alone Transmission Companies 

(American Transmission Company LLC; International 

Transmission Company; and Michigan Electric 

Transmission Company, LLC) 

NARUC National Association of Regulatory Utility 

Commissioners 

National Grid National Grid USA 

NCPA Northern California Power Agency 

Newmont Mining Newmont USA Limited, d/b/a Newmont Mining 

Corporation 

 451 A “+

” indicates that the commenter also filed supplemental comments. 
Docket Nos. RM05-25-000 and RM05-17-000 - 382 – 

Abbreviation RM05-25-000 Reply Comments 

Northwest IPPs Northwest Independent Power Producers Coalition (BP 

Energy; Calpine Corporation; EPCOR; National 

Energy Systems Company; Northwest Energy 

Development; Sempra Generation; Suez Energy North 

America, Inc.; and TransAlta Energy Marketing, (U.S.) 

Inc.) 

NRECA National Rural Electric Cooperative Association 

Occidental Occidental Chemical Corporation 

PacifiCorp PacifiCorp 

Powerex Powerex Corp. 

Progress Energy Progress Energy, Inc. (Carolina Power & Light 

Company d/b/a Progress Energy Carolinas and Florida 

Power Corporation, d/b/a Progress Energy Florida) 

Puget Puget Sound Energy, Inc. 

Sacramento Sacramento Municipal Utility District 

Salt River Salt River Project Agricultural Improvement and 

Power District 

San Antonio San Antonio City Public Service Board 

Seattle City of Seattle - City Light Department 

South Carolina 

Regulatory Staff 

South Carolina Office of Regulatory Staff 

Southern Southern Company Services, Inc. 

TANC Transmission Agency of Northern California 

TAPS Transmission Access Policy Study Group 

TDU Systems Transmission Dependent Utilities Systems 

Truckee Donner Truckee Donner Public Utility District 

TVA Tennessee Valley Authority 
Docket Nos. RM05-25-000 and RM05-17-000 - 383 – 

Abbreviation RM05-25-000 Reply Comments 

TVA Noticing 

Distributors+

TVA Noticing Distributors (Paducah Power Systems, 

Glasgow Electric Plant Board, Princeton Electric Plant 

Board and Hopkinsville Electric System) 

Williams Williams Power Company, Inc. 
Docket Nos. RM05-25-000 and RM05-17-000 - 384 – 

Commenters in RM05-17-000 

Abbreviation RM05-17-000 Comments 

Allegheny Allegheny Power 

APPA American Public Power Association 

Bonneville Bonneville Power Administration 

CEOB California Electricity Oversight Board 

EEI Edison Electric Institute 

EPSA Electric Power Supply Association 

Exelon Exelon Corporation 

FTC Federal Trade Commission 

Generator Coalition Generator Coalition (Cottonwood Energy Company 

LP; KGen Power Management Inc.; Suez Energy 

North America, Inc.; and Union Power Partners, LP) 

International 

Transmission 

International Transmission Company 

ISO/RTO ISO/RTO Council 

LDWP City of Los Angeles Department of Water and Power 

MidAmerican MidAmerican Energy Company 

MISO Midwest Independent Transmission System Operator, 

Inc. 

NERC North American Electric Reliability Council 

NY Commission New York State Public Service Commission 

PG&E Pacific Gas and Electric Company 

PGP Public Generating Pool 

Powerex Powerex Corp. 
Docket Nos. RM05-25-000 and RM05-17-000 - 385 – 

Abbreviation RM05-17-000 Comments 

Southern Southern Company Services, Inc. 

Southern California 

Edison 

Southern California Edison Company* 

TANC Transmission Agency of Northern California 

TAPS Transmission Access Policy Study Group 

WestConnect WestConnect Public Utilities 
 

Appendix B

RM05-25-000 & RM05-17-000 

(Issued May 19, 2006) 

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 Economy Energy: ..........................................................................................12

1.13 Eligible Customer:.........................................................................................12

1.14 Facilities Study: .............................................................................................13

1.15 Firm Point-To-Point Transmission Service:..................................................14

1.16 Good Utility Practice:....................................................................................14

1.17 Interruption:...................................................................................................14

1.18 Load Ratio Share: ..........................................................................................15

1.19 Load Shedding:..............................................................................................15

1.20 Long-Term Firm Point-To-Point Transmission Service: ..............................15

1.21 Native Load Customers: ................................................................................15

1.22 Network Customer:........................................................................................15

1.23 Network Integration Transmission Service:..................................................16

1.24 Network Load:...............................................................................................16

1.25 Network Operating Agreement: ....................................................................16

1.26 Network Operating Committee: ....................................................................17

1.27 Network Resource: ........................................................................................17

1.28 Network Upgrades:........................................................................................17

1.29 Non-Firm Point-To-Point Transmission Service: .........................................17

1.30 Non-Firm Sale: ..............................................................................................18

1.31 Open Access Same-Time Information System (OASIS): .............................18

1.32 Part I: .............................................................................................................18

1.33 Part II: ............................................................................................................18

1.34 Part III:...........................................................................................................18

1.35 Parties: ...........................................................................................................19
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 3 

1.36 Point(s) of Delivery: ......................................................................................19

1.37 Point(s) of Receipt:........................................................................................19

1.38 Point-To-Point Transmission Service: ..........................................................19

1.39 Power Purchaser: ...........................................................................................20

1.40 Pre-Confirmed Application: ..........................................................................20

1.41 Receiving Party: ............................................................................................20

1.42 Regional Transmission Group (RTG): ..........................................................20

1.43 Reserved Capacity:........................................................................................20

1.44 Service Agreement: .......................................................................................21

1.45 Service Commencement Date: ......................................................................21

1.46 Short-Term Firm Point-To-Point Transmission Service:..............................21

1.47 System Impact Study:....................................................................................21

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 Sources Service:....27

3.3 Regulation and Frequency Response Service: ..............................................27

3.4 Energy Imbalance Service:............................................................................27

3.5 Operating Reserve - Spinning Reserve Service: ...........................................27

3.6 Operating Reserve - Supplemental Reserve Service:....................................28

4 OPEN ACCESS SAME-TIME INFORMATION SYSTEM (OASIS)................................28

5 LOCAL FURNISHING BONDS...................................................................................28

5.1 Transmission Providers That Own Facilities Financed by Local Furnishing 

Bonds: 28

5.2 Alternative Procedures for Requesting Transmission Service:.....................29

6 RECIPROCITY..........................................................................................................30

7 BILLING AND PAYMENT .........................................................................................31

7.1 Billing Procedure:..........................................................................................31

7.2 Interest on Unpaid Balances:.........................................................................31
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 4 

7.3 Customer Default:..........................................................................................32

8 ACCOUNTING FOR THE TRANSMISSION PROVIDER'S USE OF THE TARIFF..............33

8.1 Transmission Revenues:................................................................................33

8.2 Study Costs and Revenues: ...........................................................................33

9 REGULATORY FILINGS ...........................................................................................34

10 FORCE MAJEURE AND INDEMNIFICATION..............................................................34

10.1 Force Majeure:...............................................................................................34

10.2 Indemnification:.............................................................................................35

11 CREDITWORTHINESS ..............................................................................................35

12 DISPUTE RESOLUTION PROCEDURES .....................................................................35

12.1 Internal Dispute Resolution Procedures:.......................................................35

12.2 External Arbitration Procedures:...................................................................36

12.3 Arbitration Decisions:....................................................................................37

12.4 Costs: .............................................................................................................38

12.5 Rights Under The Federal Power Act: ..........................................................38

II. POINT-TO-POINT TRANSMISSION SERVICE...............................................38

13 NATURE OF FIRM POINT-TO-POINT TRANSMISSION SERVICE ...............................38

13.1 Term: .............................................................................................................39

13.2 Reservation Priority:......................................................................................39

13.3 Use of Firm Transmission Service by the Transmission Provider:...............41

13.4 Service Agreements:......................................................................................41

13.5 Transmission Customer Obligations for Facility Additions or Redispatch 

Costs: 42

13.6 Curtailment of Firm Transmission Service: ..................................................43

13.7 Classification of Firm Transmission Service: ...............................................44

13.8 Scheduling of Firm Point-To-Point Transmission Service: ..........................46

14 NATURE OF NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE ......................48

14.1 Term: .............................................................................................................48

14.2 Reservation Priority:......................................................................................48

14.3 Use of Non-Firm Point-To-Point Transmission Service by the Transmission 

Provider: ....................................................................................................................50

14.4 Service Agreements:......................................................................................50

14.5 Classification of Non-Firm Point-To-Point Transmission Service:..............50

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service:..................51

14.7 Curtailment or Interruption of Service: .........................................................53

15 SERVICE AVAILABILITY.........................................................................................54
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 5 

15.1 General Conditions:.......................................................................................54

15.2 Determination of Available Transfer Capability:..........................................55

15.3 Initiating Service in the Absence of an Executed Service Agreement:.........55

15.4 Obligation to Provide Transmission Service that Requires Expansion or 

Modification of the Transmission System:................................................................56

15.5 Deferral of Service: .......................................................................................57

15.6 Other Transmission Service Schedules: ........................................................57

15.7 Real Power Losses:........................................................................................57

16 TRANSMISSION CUSTOMER RESPONSIBILITIES ......................................................58

16.1 Conditions Required of Transmission Customers:........................................58

16.2 Transmission Customer Responsibility for Third-Party Arrangements:.......59

17 PROCEDURES FOR ARRANGING FIRM POINT-TO-POINT TRANSMISSION SERVICE 59

17.1 Application: ...................................................................................................59

17.2 Completed Application:.................................................................................60

17.3 Deposit:..........................................................................................................62

17.4 Notice of Deficient Application: ...................................................................64

17.5 Response to a Completed Application: .........................................................64

17.6 Execution of Service Agreement:..................................................................65

17.7 Extensions for Commencement of Service: ..................................................65

18 PROCEDURES FOR ARRANGING NON-FIRM POINT-TO-POINT TRANSMISSION 

SERVICE .........................................................................................................................66

18.1 Application: ...................................................................................................66

18.2 Completed Application:.................................................................................67

18.3 Reservation of Non-Firm Point-To-Point Transmission Service:.................68

18.4 Determination of Available Transfer Capability:..........................................69

19 ADDITIONAL STUDY PROCEDURES FOR FIRM POINT-TO-POINT TRANSMISSION 

SERVICE REQUESTS........................................................................................................69

19.1 Notice of Need for System Impact Study:.....................................................69

19.2 System Impact Study Agreement and Cost Reimbursement: .......................70

19.3 System Impact Study Procedures:.................................................................71

19.4 Facilities Study Procedures: ..........................................................................72

19.5 Facilities Study Modifications:......................................................................74

19.6 Due Diligence in Completing New Facilities:...............................................75

19.7 Partial Interim Service:..................................................................................75

19.8 Expedited Procedures for New Facilities: .....................................................75

19.9 Penalties for Failure to Meet Study Deadlines:.............................................76

20 PROCEDURES IF THE TRANSMISSION PROVIDER IS UNABLE TO COMPLETE NEW 

TRANSMISSION FACILITIES FOR FIRM POINT-TO-POINT TRANSMISSION SERVICE........79
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 6 

20.1 Delays in Construction of New Facilities:.....................................................79

20.2 Alternatives to the Original Facility Additions: ............................................79

20.3 Refund Obligation for Unfinished Facility Additions:..................................80

21 PROVISIONS RELATING TO TRANSMISSION CONSTRUCTION AND SERVICES ON THE 

SYSTEMS OF OTHER UTILITIES ......................................................................................80

21.1 Responsibility for Third-Party System Additions:........................................81

21.2 Coordination of Third-Party System Additions: ...........................................81

22 CHANGES IN SERVICE SPECIFICATIONS..................................................................82

22.1 Modifications On a Non-Firm Basis: ............................................................82

22.2 Modification On a Firm Basis: ......................................................................83

23 SALE OR ASSIGNMENT OF TRANSMISSION SERVICE ..............................................84

23.1 Procedures for Assignment or Transfer of Service: ......................................84

23.2 Limitations on Assignment or Transfer of Service: ......................................85

23.3 Information on Assignment or Transfer of Service: .....................................86

24 METERING AND POWER FACTOR CORRECTION AT RECEIPT AND DELIVERY 

POINTS(S) .......................................................................................................................86

24.1 Transmission Customer Obligations: ............................................................86

24.2 Transmission Provider Access to Metering Data:.........................................86

24.3 Power Factor:.................................................................................................86

25 COMPENSATION FOR TRANSMISSION SERVICE ......................................................87

26 STRANDED COST RECOVERY .................................................................................87

27 COMPENSATION FOR NEW FACILITIES AND REDISPATCH COSTS ..........................87

III. NETWORK INTEGRATION TRANSMISSION SERVICE .............................88

28 NATURE OF NETWORK INTEGRATION TRANSMISSION SERVICE ............................88

28.1 Scope of Service:...........................................................................................88

28.2 Transmission Provider Responsibilities: .......................................................89

28.3 Network Integration Transmission Service:..................................................90

28.4 Secondary Service: ........................................................................................90

28.5 Real Power Losses:........................................................................................91

28.6 Restrictions on Use of Service: .....................................................................91

29 INITIATING SERVICE...............................................................................................91

29.1 Condition Precedent for Receiving Service: .................................................91

29.2 Application Procedures: ................................................................................92

29.3 Technical Arrangements to be Completed Prior to Commencement of 

Service: ......................................................................................................................98

29.4 Network Customer Facilities:........................................................................98
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 7 

29.5 Filing of Service Agreement: ........................................................................99

30 NETWORK RESOURCES ..........................................................................................99

30.1 Designation of Network Resources:..............................................................99

30.2 Designation of New Network Resources: .....................................................99

30.3 Termination of Network Resources: ...........................................................100

30.4 Operation of Network Resources: ...............................................................101

30.5 Network Customer Redispatch Obligation:.................................................102

30.6 Transmission Arrangements for Network Resources Not Physically 

Interconnected With The Transmission Provider:...................................................102

30.7 Limitation on Designation of Network Resources:.....................................102

30.8 Use of Interface Capacity by the Network Customer: ................................103

30.9 Network Customer Owned Transmission Facilities:...................................103

31 DESIGNATION OF NETWORK LOAD ......................................................................104

31.1 Network Load:.............................................................................................104

31.2 New Network Loads Connected With the Transmission Provider: ............104

31.3 Network Load Not Physically Interconnected with the Transmission 

Provider: ..................................................................................................................105

31.4 New Interconnection Points: .......................................................................105

31.5 Changes in Service Requests:......................................................................106

31.6 Annual Load and Resource Information Updates: ......................................106

32 ADDITIONAL STUDY PROCEDURES FOR NETWORK INTEGRATION TRANSMISSION 

SERVICE REQUESTS......................................................................................................107

32.1 Notice of Need for System Impact Study:...................................................107

32.2 System Impact Study Agreement and Cost Reimbursement: .....................108

32.3 System Impact Study Procedures:...............................................................109

32.4 Facilities Study Procedures: ........................................................................110

32.5 Penalties for Failure to Meet Study Deadlines:...........................................112

33 LOAD SHEDDING AND CURTAILMENTS................................................................112

33.1 Procedures: ..................................................................................................112

33.2 Transmission Constraints: ...........................................................................112

33.3 Cost Responsibility for Relieving Transmission Constraints: ....................113

33.4 Curtailments of Scheduled Deliveries:........................................................113

33.5 Allocation of Curtailments: .........................................................................114

33.6 Load Shedding:............................................................................................114

33.7 System Reliability: ......................................................................................115

34 RATES AND CHARGES ..........................................................................................116

34.1 Monthly Demand Charge: ...........................................................................116

34.2 Determination of Network Customer's Monthly Network Load:................116
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 8 

34.3 Determination of Transmission Provider's Monthly Transmission System 

Load: 116

34.4 Redispatch Charge:......................................................................................117

34.5 Stranded Cost Recovery: .............................................................................117

35 OPERATING ARRANGEMENTS ..............................................................................117

35.1 Operation under The Network Operating Agreement:................................117

35.2 Network Operating Agreement: ..................................................................118

35.3 Network Operating Committee: ..................................................................119

SCHEDULE 1 ................................................................................................................120

SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE ....................................120

SCHEDULE 2 ................................................................................................................121

REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION SOURCES 

SERVICE ......................................................................................................................121

SCHEDULE 3 ................................................................................................................123

REGULATION AND FREQUENCY RESPONSE SERVICE...............................................123

SCHEDULE 4 ................................................................................................................124

ENERGY IMBALANCE SERVICE..................................................................................124

SCHEDULE 5 ................................................................................................................126

OPERATING RESERVE - SPINNING RESERVE SERVICE.............................................126

SCHEDULE 6 ................................................................................................................127

OPERATING RESERVE - SUPPLEMENTAL RESERVE SERVICE ..................................127

SCHEDULE 7 ................................................................................................................128

LONG-TERM FIRM AND SHORT-TERM FIRM POINT-TO-POINT..............................128

SCHEDULE 8 ................................................................................................................130

NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE...........................................130

SCHEDULE 9 ................................................................................................................132

GENERATOR IMBALANCE SERVICE...........................................................................132

ATTACHMENT A ........................................................................................................133

FORM OF SERVICE AGREEMENT FOR FIRM POINT-TO-POINT TRANSMISSION 

SERVICE ......................................................................................................................133

ATTACHMENT B ........................................................................................................137
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 9 

FORM OF SERVICE AGREEMENT FOR NON-FIRM POINT-TO-POINT TRANSMISSION 

SERVICE ......................................................................................................................137

ATTACHMENT C ........................................................................................................139

METHODOLOGY TO ASSESS AVAILABLE TRANSFER CAPABILITY..........................139

ATTACHMENT D ........................................................................................................141

METHODOLOGY FOR COMPLETING A SYSTEM IMPACT STUDY ..............................141

ATTACHMENT E ........................................................................................................142

INDEX OF POINT-TO-POINT TRANSMISSION SERVICE CUSTOMERS.......................142

ATTACHMENT F.........................................................................................................143

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION SERVICE...143

ATTACHMENT G........................................................................................................144

NETWORK OPERATING AGREEMENT........................................................................144

ATTACHMENT H........................................................................................................145

ANNUAL TRANSMISSION REVENUE REQUIREMENT FOR NETWORK INTEGRATION 

TRANSMISSION SERVICE ............................................................................................145

ATTACHMENT I..........................................................................................................146

INDEX OF NETWORK INTEGRATION TRANSMISSION SERVICE CUSTOMERS..........146

ATTACHMENT J .........................................................................................................147

PROCEDURES FOR ADDRESSING PARALLEL FLOWS ................................................147

ATTACHMENT K........................................................................................................148

TRANSMISSION PLANNING PROCESS.........................................................................148

ATTACHMENT L ........................................................................................................149

CREDITWORTHINESS PROCEDURES ..........................................................................149
(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 Economy Energy: 

Energy purchased by a Network Integration Transmission customer that 

displaces that customer’s own higher cost designated Network Resource(s) for 

the purpose of serving that customer’s designated Network Load(s). 

1.13 Eligible Customer: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 13 

i. Any electric utility (including the Transmission Provider and any 

power marketer), Federal power marketing agency, or any person 

generating electric energy for sale for resale is an Eligible Customer 

under the Tariff. Electric energy sold or produced by such entity may 

be electric energy produced in the United States, Canada or Mexico. 

However, with respect to transmission service that the Commission is 

prohibited from ordering by Section 212(h) of the Federal Power Act, 

such entity is eligible only if the service is provided pursuant to a state 

requirement that the Transmission Provider offer the unbundled 

transmission service, or pursuant to a voluntary offer of such service by 

the Transmission Provider. 

ii. Any retail customer taking unbundled transmission service pursuant to 

a state requirement that the Transmission Provider offer the 

transmission service, or pursuant to a voluntary offer of such service by 

the Transmission Provider, is an Eligible Customer under the Tariff. 

1.14 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 14 

service. 

1.15 Firm Point-To-Point Transmission Service: 

Transmission Service under this Tariff that is reserved and/or scheduled 

between specified Points of Receipt and Delivery pursuant to Part II of this 

Tariff. 

1.16 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). 

1.17 Interruption: 

A reduction in non-firm transmission service due to economic reasons 

pursuant to Section 14.7. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 15 

1.18 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 the Tariff and 

calculated on a rolling twelve month basis. 

1.19 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. 

1.20 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. 

1.21 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. 

1.22 Network Customer: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 16 

An entity receiving transmission service pursuant to the terms of the 

Transmission Provider's Network Integration Transmission Service under Part 

III of the Tariff. 

1.23 Network Integration Transmission Service: 

The transmission service provided under Part III of the Tariff. 

1.24 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. 

1.25 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 17 

matters associated with the implementation of Network Integration 

Transmission Service under Part III of the Tariff. 

1.26 Network Operating Committee: 

A group made up of representatives from the Network Customer(s) and the 

Transmission Provider established to coordinate operating criteria and other 

technical considerations required for implementation of Network Integration 

Transmission Service under Part III of this Tariff. 

1.27 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. 

1.28 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. 

1.29 Non-Firm Point-To-Point Transmission Service: 

Point-To-Point Transmission Service under the Tariff that is reserved and 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 18 

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. 

1.30 Non-Firm Sale: 

An energy sale for which receipt or delivery may be interrupted for any reason 

or no reason, without liability on the part of either the buyer or seller. 

1.31 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. 

1.32 Part I: 

Tariff Definitions and Common Service Provisions contained in Sections 2 

through 12. 

1.33 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. 

1.34 Part III: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 19 

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. 

1.35 Parties: 

The Transmission Provider and the Transmission Customer receiving service 

under the Tariff. 

1.36 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. 

1.37 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. 

1.38 Point-To-Point Transmission Service: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 20 

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. 

1.39 Power Purchaser: 

The entity that is purchasing the capacity and energy to be transmitted under 

the Tariff. 

1.40 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. 

1.41 Receiving Party: 

The entity receiving the capacity and energy transmitted by the Transmission 

Provider to Point(s) of Delivery. 

1.42 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. 

1.43 Reserved Capacity: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 21 

The maximum amount of capacity and energy that the Transmission Provider 

agrees to transmit for the Transmission Customer over the Transmission 

Provider's Transmission System between the Point(s) of Receipt and the 

Point(s) of Delivery under Part II of the Tariff. Reserved Capacity shall be 

expressed in terms of whole megawatts on a sixty (60) minute interval 

(commencing on the clock hour) basis. 

1.44 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. 

1.45 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. 

1.46 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. 

1.47 System Impact Study: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 22 

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: 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 23 

1.51 Transmission Provider's Monthly Transmission System Peak: 

The maximum firm usage of the Transmission Provider's Transmission 

System in a calendar month. 

1.52 Transmission Service: 

Point-To-Point Transmission Service provided under Part II of the Tariff on a 

firm and non-firm basis. 

1.53 Transmission System: 

The facilities owned, controlled or operated by the Transmission Provider that 

are used to provide transmission service under Part II and Part III of the Tariff. 

2 Initial Allocation and Renewal Procedures 

2.1 Initial Allocation of Available Transfer Capability: 

For purposes of determining whether existing capability on the Transmission 

Provider's Transmission System is adequate to accommodate a request for 

firm service under this Tariff, all Completed Applications for new firm 

transmission service received during the initial sixty (60) day period 

commencing with the effective date of the Tariff will be deemed to have been 

filed simultaneously. A lottery system conducted by an independent party 

shall be used to assign priorities for Completed Applications filed 

simultaneously. All Completed Applications for firm transmission service 

received after the initial sixty (60) day period shall be assigned a priority 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 24 

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 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 25 

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 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, and (iv) Operating Reserve 

- Supplemental. 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-
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 26 

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. 

 If the Transmission Provider is a public utility providing transmission 

service but is not a Control Area operator, it may be unable to provide some or all 

of the Ancillary Services. In this case, the Transmission Provider can fulfill its 

obligation to provide Ancillary Services by acting as the Transmission Customer's 

agent to secure these Ancillary Services from the Control Area operator. The 

Transmission Customer may elect to (i) have the Transmission Provider act as its 

agent, (ii) secure the Ancillary Services directly from the Control Area operator, or 

(iii) secure the Ancillary Services (discussed in Schedules 3, 4, 5 and 6) 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 27 

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 3.6 below list the six Ancillary Services. 

3.1 Scheduling, System Control and Dispatch Service: 

The rates and/or methodology are described in Schedule 1. 

3.2 Reactive Supply and Voltage Control from Generation 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 28 

3.6 Operating Reserve - Supplemental Reserve Service: 

Where applicable the rates and/or methodology are described in Schedule 6. 

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 

(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. 

5 Local Furnishing Bonds 

5.1 Transmission Providers That Own Facilities Financed by Local 

Furnishing Bonds: 

This provision is applicable only to Transmission Providers that have financed 

facilities for the local furnishing of electric energy with 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 29 

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 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 30 

order under Section 211 of the Federal Power Act. Upon issuance 

of the order under Section 211 of the Federal Power Act, the 

Transmission Provider shall be required to provide the requested 

transmission service in accordance with the terms and conditions 

of this Tariff. 

6 Reciprocity 

 A Transmission Customer receiving transmission service under this Tariff 

agrees to provide comparable transmission service that it is capable of providing to 

the Transmission Provider on similar terms and conditions over facilities used for 

the transmission of electric energy owned, controlled or operated by the 

Transmission Customer and over facilities used for the transmission of electric 

energy owned, controlled or operated by the Transmission Customer's corporate 

affiliates. A Transmission Customer that is a member of a power pool or Regional 

Transmission Group also agrees to provide comparable transmission service to the 

members of such power pool and Regional Transmission Group 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 31 

that obtains transmission service under the Tariff, but also to all parties to a 

transaction that involves the use of transmission service under the Tariff, including 

the power seller, buyer and any intermediary, such as a power marketer. This 

reciprocity requirement also applies to any Eligible Customer that owns, controls 

or operates transmission facilities that uses an intermediary, such as a power 

marketer, to request transmission service under the Tariff. If the Transmission 

Customer does not own, control or operate transmission facilities, it must include 

in its Application a sworn statement of one of its duly authorized officers or other 

representatives that the purpose of its Application is not to assist an Eligible 

Customer to avoid the requirements of this provision. 

7 Billing and Payment 

7.1 Billing Procedure: 

Within a reasonable time after the first day of each month, the Transmission 

Provider shall submit an invoice to the Transmission Customer for the charges 

for all services furnished under the Tariff during the preceding month. The 

invoice shall be paid by the Transmission Customer within twenty (20) days 

of receipt. All payments shall be made in immediately available funds 

payable to the Transmission Provider, or by wire transfer to a bank named by 

the Transmission Provider. 

7.2 Interest on Unpaid Balances: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 32 

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. 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 33 

make all payments not in dispute, and (ii) pays into an independent escrow 

account the portion of the invoice in dispute, pending resolution of such 

dispute. If the Transmission Customer fails to meet these two requirements 

for continuation of service, then the Transmission Provider may provide 

notice to the Transmission Customer of its intention to suspend service in 

sixty (60) days, in accordance with Commission policy. 

8 Accounting for the Transmission Provider's Use of the Tariff 

 The Transmission Provider shall record the following amounts, as outlined 

below. 

8.1 Transmission Revenues: 

Include in a separate operating revenue account or subaccount the revenues it 

receives from Transmission Service when making Third-Party Sales under 

Part II of the Tariff. 

8.2 Study Costs and Revenues: 

Include in a separate transmission operating expense account or subaccount, 

costs properly chargeable to expense that are incurred to perform any System 

Impact Studies or Facilities Studies which the Transmission Provider conducts 

to determine if it must construct new transmission facilities or upgrades 

necessary for its own uses, including making Third-Party Sales under the 

Tariff; and include in a separate operating revenue account or subaccount the 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 34 

revenues received for System Impact Studies or Facilities Studies performed 

when such amounts are separately stated and identified in the Transmission 

Customer's billing under the Tariff. 

9 Regulatory Filings 

 Nothing contained in the Tariff or any Service Agreement shall be 

construed as affecting in any way the right of the Transmission Provider to 

unilaterally make application to the Commission for a change in rates, terms and 

conditions, charges, classification of service, Service Agreement, rule or 

regulation under Section 205 of the Federal Power Act and pursuant to the 

Commission's rules 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 35 

event does not include an act of negligence or intentional wrongdoing. 

Neither the Transmission Provider nor the Transmission Customer will be 

considered in default as to any obligation under this Tariff if prevented from 

fulfilling the obligation due to an event of Force Majeure. However, a Party 

whose performance under this Tariff is hindered by an event of Force Majeure 

shall make all reasonable efforts to perform its obligations under this Tariff. 

10.2 Indemnification: 

The Transmission Customer shall at all times indemnify, defend, and save the 

Transmission Provider harmless from, any and all damages, losses, claims, 

including claims and actions relating to injury to or death of any person or 

damage to property, demands, suits, recoveries, costs and expenses, court 

costs, attorney fees, and all other obligations by or to third parties, arising out 

of or resulting from the Transmission Provider’s performance of its 

obligations under this Tariff on behalf of the Transmission Customer, except 

in cases of negligence or intentional wrongdoing by the Transmission 

Provider. 

11 Creditworthiness 

 The Transmission Provider will specify its Creditworthiness procedures in 

Attachment L. 

12 Dispute Resolution Procedures 

12.1 Internal Dispute Resolution Procedures: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 36 

Any dispute between a Transmission Customer and the Transmission Provider 

involving transmission service under the Tariff (excluding applications for 

rate changes or other changes to the Tariff, or to any Service Agreement 

entered into under the Tariff, which shall be presented directly to the 

Commission for resolution) shall be referred to a designated senior 

representative of the Transmission Provider and a senior representative of the 

Transmission Customer for resolution on an informal basis as promptly as 

practicable. In the event the designated representatives are unable to resolve 

the dispute within thirty (30) days [or such other period as the Parties may 

agree upon] by mutual agreement, such dispute may be submitted to 

arbitration and resolved in accordance with the arbitration procedures set forth 

below. 

12.2 External Arbitration Procedures: 

Any arbitration initiated under the Tariff shall be conducted before a single 

neutral arbitrator appointed by the Parties. If the Parties fail to agree upon a 

single arbitrator within ten (10) days of the referral of the dispute to 

arbitration, each Party shall choose one arbitrator who shall sit on a threemember arbitration panel. The two arbitrators so chosen shall within twenty 

(20) days select a third arbitrator to chair the arbitration panel. In either case, 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 37 

the arbitrators shall be knowledgeable in electric utility matters, including 

electric transmission and bulk power issues, and shall not have any current or 

past substantial business or financial relationships with any party to the 

arbitration (except prior arbitration). The arbitrator(s) shall provide each of 

the Parties an opportunity to be heard and, except as otherwise provided 

herein, shall generally conduct the arbitration in accordance with the 

Commercial Arbitration Rules of the American Arbitration Association and 

any applicable Commission regulations or Regional Transmission Group 

rules. 

12.3 Arbitration Decisions: 

Unless otherwise agreed, the arbitrator(s) shall render a decision within ninety 

(90) days of appointment and shall notify the Parties in writing of such 

decision and the reasons therefor. The arbitrator(s) shall be authorized only to 

interpret and apply the provisions of the Tariff and any Service Agreement 

entered into under the Tariff and shall have no power to modify or change any 

of the above in any manner. The decision of the arbitrator(s) shall be final and 

binding upon the Parties, and judgment on the award may be entered in any 

court having jurisdiction. The decision of the arbitrator(s) may be appealed 

solely on the grounds that the conduct of the arbitrator(s), or the decision 

itself, violated the standards set forth in the Federal Arbitration Act and/or the 
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Administrative Dispute Resolution Act. The final decision of the arbitrator 

must also be filed with the Commission if it affects jurisdictional rates, terms 

and conditions of service or facilities. 

12.4 Costs: 

Each Party shall be responsible for its own costs incurred during the 

arbitration process and for the following costs, if applicable: 

1. the cost of the arbitrator chosen by the Party to sit on the three member 

panel and one half of the cost of the third arbitrator chosen; or 

2. one half the cost of the single arbitrator jointly chosen by the Parties. 

12.5 Rights Under The Federal Power Act: 

Nothing in this section shall restrict the rights of any party to file a Complaint 

with the Commission under relevant provisions of the Federal Power Act. 

II. POINT-TO-POINT TRANSMISSION SERVICE 

Preamble 

 The Transmission Provider will provide Firm and Non-Firm Point-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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 39 

13.1 Term: 

The minimum term of Firm Point-To-Point Transmission Service shall be one 

hour and the maximum term shall be specified in the Service Agreement. 

13.2 Reservation Priority: 

(i) Long-Term Firm Point-To-Point Transmission Service shall be 

available on a first-come, first-served basis, i.e., in the 

chronological sequence in which each Transmission Customer has 

requested service. However, Pre-Confirmed Applications for 

service will receive priority over earlier-submitted requests that 

are not Pre-Confirmed. Within classes of requests (PreConfirmed or not confirmed), the highest price offered by the 

Eligible Customer is the first tiebreaker, followed by the date and 

time of the request. 

(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. 

Within classes of requests (Pre-Confirmed or not confirmed), 

duration is the first tiebreaker, followed by the highest price 
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offered by the Eligible Customer, 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 hour before the commencement 

of hourly service, 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 has the right 

of first refusal to match any longer term reservation 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. After the conditional 
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Original Sheet No. 41 

reservation deadline, service will commence pursuant to the terms 

of Part II of the Tariff. 

(iv) Firm Point-To-Point Transmission Service will always have a 

reservation priority over Non-Firm Point-To-Point Transmission 

Service under the Tariff. All Long-Term Firm Point-To-Point 

Transmission Service will have equal reservation priority with 

Native Load Customers and Network Customers. Reservation 

priorities for existing firm service customers are provided in 

Section 2.2. 

13.3 Use of Firm Transmission Service by the Transmission Provider: 

The Transmission Provider will be subject to the rates, terms and conditions of 

Part II of the Tariff when making Third-Party Sales under (i) agreements 

executed on or after [insert date sixty (60) days after publication in Federal 

Register] or (ii) agreements executed prior to the aforementioned date that the 

Commission requires to be unbundled, by the date specified by the 

Commission. The Transmission Provider will maintain separate accounting, 

pursuant to Section 8, for any use of the Point-To-Point Transmission Service 

to make Third-Party Sales. 

13.4 Service Agreements: 

The Transmission Provider shall offer a standard form Firm Point-To-Point 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 42 

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 ShortTerm 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. 

13.5 Transmission Customer Obligations for Facility Additions or 

Redispatch Costs: 

In cases where the Transmission Provider determines that the Transmission 

System is not capable of providing Firm Point-To-Point Transmission Service 

without (1) degrading or impairing the reliability of service to Native Load 

Customers, Network Customers and other Transmission Customers taking 

Firm Point-To-Point Transmission Service, or (2) interfering with the 

Transmission Provider's ability to meet prior firm contractual commitments to 

others, the Transmission Provider will be obligated to expand or upgrade its 

Transmission System pursuant to the terms of Section 15.4. The Transmission 

Customer must agree to compensate the Transmission Provider for any 
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Original Sheet No. 43 

necessary transmission facility additions pursuant to the terms of Section 27. 

To the extent the Transmission Provider can relieve any system constraint 

more economically by redispatching the Transmission Provider's resources 

than through constructing Network Upgrades, it shall do so, provided that the 

Eligible Customer agrees to compensate the Transmission Provider pursuant 

to the terms of Section 27. Any redispatch, Network Upgrade or Direct 

Assignment Facilities costs to be charged to the Transmission Customer on an 

incremental basis under the Tariff will be specified in the Service Agreement 

prior to initiating service. 

13.6 Curtailment of Firm Transmission Service: 

In the event that a Curtailment on the Transmission Provider's Transmission 

System, or a portion thereof, is required to maintain reliable operation of such 

system and the system directly and indirectly interconnected with 

Transmission Provider’s Transmission system. Curtailments will be made on 

a non-discriminatory basis to the transaction(s) that effectively relieve the 

constraint. Transmission Provider may elect to implement such Curtailments 

pursuant to the Transmission Loading Relief procedures specified in 

Attachment J. If multiple transactions require Curtailment, to the extent 

practicable and consistent with Good Utility Practice, the Transmission 

Provider will curtail service to Network Customers and Transmission 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 44 

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. When the Transmission Provider 

determines that an electrical emergency exists on its Transmission System and 

implements emergency procedures to Curtail Firm Transmission Service, the 

Transmission Customer shall make the required reductions upon request of the 

Transmission Provider. However, the Transmission Provider reserves the 

right to Curtail, in whole or in part, any Firm Transmission Service provided 

under the Tariff when, in the Transmission Provider's sole discretion, an 

emergency or other unforeseen condition impairs or degrades the reliability of 

its Transmission System. The Transmission Provider will notify all affected 

Transmission Customers in a timely manner of any scheduled Curtailments. 

13.7 Classification of Firm Transmission Service: 

(a) The Transmission Customer taking Firm Point-To-Point 

Transmission Service may (1) change its Receipt and Delivery 

Points to obtain service on a non-firm basis consistent with the 

terms of Section 22.1 or (2) request a modification of the Points 

of Receipt or Delivery on a firm basis pursuant to the terms of 
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Original Sheet No. 45 

Section 22.2. 

(b) The Transmission Customer may purchase transmission service to 

make sales of capacity and energy from multiple generating units 

that are on the Transmission Provider's Transmission System. For 

such a purchase of transmission service, the resources will be 

designated as multiple Points of Receipt, unless the multiple 

generating units are at the same generating plant in which case the 

units would be treated as a single Point of Receipt. 

(c) The Transmission Provider shall provide firm deliveries of 

capacity and energy from the Point(s) of Receipt to the Point(s) of 

Delivery. Each Point of Receipt at which firm transmission 

capacity is reserved by the Transmission Customer shall be set 

forth in the Firm Point-To-Point Service Agreement for 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 Long-
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 46 

Term Firm Transmission Service along with a corresponding 

capacity reservation associated with each Point of Delivery. 

Points of Delivery and corresponding capacity reservations shall 

be as mutually agreed upon by the Parties for Short-Term Firm 

Transmission. The greater of either (1) the sum of the capacity 

reservations at the Point(s) of Receipt, or (2) the sum of the 

capacity reservations at the Point(s) of Delivery shall be the 

Transmission Customer's Reserved Capacity. The Transmission 

Customer will be billed for its Reserved Capacity under the terms 

of Schedule 7. The Transmission Customer may not exceed its 

firm capacity reserved at each Point of Receipt and each Point of 

Delivery except as otherwise specified in Section 22. The 

Transmission Provider shall specify the rate treatment and all 

related terms and conditions applicable in the event that a 

Transmission Customer (including Third-Party Sales by the 

Transmission Provider) exceeds its firm reserved capacity at any 

Point of Receipt or Point of Delivery or uses Transmission 

Service at a Point of Receipt or Point of Delivery that it has not 

reserved. 

13.8 Scheduling of Firm Point-To-Point Transmission Service: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 47 

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 

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. 

Transmission customers may also batch requests and schedules for hourly firm 

service to be provided on the same day. 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 
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Original Sheet No. 48 

schedules equal to those furnished by the Receiving Party (unless reduced for 

losses) and shall deliver the capacity and energy provided by such schedules. 

Should the Transmission Customer, Delivering Party or Receiving Party 

revise or terminate any schedule, such party shall immediately notify the 

Transmission Provider, and the Transmission Provider shall have the right to 

adjust accordingly the schedule for capacity and energy to be received and to 

be delivered. 

14 Nature of Non-Firm Point-To-Point Transmission Service 

14.1 Term: 

Non-Firm Point-To-Point Transmission Service will be available for periods 

ranging from one (1) hour to one (1) month. However, a Purchaser of 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 
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Long-Term and Short-Term Firm Point-To-Point Transmission Service. A 

higher priority will be assigned first to Pre-Confirmed Applications and 

second to reservations with a longer duration of service. In the event the 

Transmission System is constrained, competing requests of the same PreConfirmation status and equal duration will be prioritized based on the highest 

price offered by the Eligible Customer for the Transmission Service. Eligible 

Customers that have already reserved shorter term service have the right of 

first refusal to match any longer term reservation before being preempted. A 

longer term competing request for 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 
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Original Sheet No. 50 

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 

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: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 51 

Non-Firm Point-To-Point Transmission Service shall be offered under terms 

and conditions contained in Part II of the Tariff. The Transmission Provider 

undertakes no obligation under the Tariff to plan its Transmission System in 

order to have sufficient capacity for Non-Firm Point-To-Point Transmission 

Service. Parties requesting Non-Firm Point-To-Point Transmission Service 

for the transmission of firm power do so with the full realization that such 

service is subject to availability and to Curtailment or Interruption under the 

terms of the Tariff. The Transmission Provider shall specify the rate treatment 

and all related terms and conditions applicable in the event that a 

Transmission Customer (including Third-Party Sales by the Transmission 

Provider) exceeds its 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 
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Original Sheet No. 52 

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 

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. 
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Original Sheet No. 53 

14.7 Curtailment or Interruption of Service: 

The Transmission Provider reserves the right to Curtail, in whole or in part, 

Non-Firm Point-To-Point Transmission Service provided under the Tariff for 

reliability reasons when, an emergency or other unforeseen condition threatens 

to impair or degrade the reliability of its Transmission System or the systems 

directly and indirectly interconnected with Transmission Provider’s 

Transmission System. Transmission Provider may elect to implement such 

Curtailments pursuant to the Transmission Loading Relief procedures 

specified in Attachment J. The Transmission Provider reserves the right to 

Interrupt, in whole or in part, 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, or 

(4) transmission service for Network Customers from non-designated 

resources. 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 
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Original Sheet No. 54 

Point-To-Point Transmission Service shall be subordinate to Firm 

Transmission Service. If multiple transactions require Curtailment or 

Interruption, to the extent practicable and consistent with Good Utility 

Practice, Curtailments or Interruptions will be made to transactions of the 

shortest term (e.g., hourly non-firm transactions will be Curtailed or 

Interrupted before daily non-firm transactions and daily non-firm transactions 

will be Curtailed or Interrupted before weekly non-firm transactions). 

Transmission service for Network Customers from resources other than 

designated Network Resources will have a higher priority than any Non-Firm 

Point-To-Point Transmission Service under the Tariff. Non-Firm Point-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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 55 

15.2 Determination of Available Transfer Capability: 

A description of the Transmission Provider's specific methodology for 

assessing available transfer capability posted on the Transmission Provider's 

OASIS (Section 4) is contained in Attachment C of the Tariff. In the event 

sufficient transfer capability may not exist to accommodate a service request, 

the Transmission Provider will respond by performing a System Impact Study. 

15.3 Initiating Service in the Absence of an Executed Service 

Agreement: 

If the Transmission Provider and the Transmission Customer requesting Firm 

or Non-Firm Point-To-Point Transmission Service cannot agree on all the 

terms and conditions of the Point-To-Point Service Agreement, the 

Transmission Provider shall file with the Commission, within thirty (30) days 

after the date the Transmission Customer provides written notification 

directing the Transmission Provider to file, an unexecuted Point-To-Point 

Service Agreement containing terms and conditions deemed appropriate by 

the Transmission Provider for such requested Transmission Service. The 

Transmission Provider shall commence providing Transmission Service 

subject to the Transmission Customer agreeing to (i) compensate the 

Transmission Provider at whatever rate the Commission ultimately determines 

to be just and reasonable, and (ii) comply with the terms and conditions of the 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 56 

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: 

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 redispatch its own resources or 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. To the 

extent a Transmission Provider cannot redispatch its own resources to provide 

the requested Firm Transmission Service, it shall identify generators in other 

control areas that could relieve the constraint and allow the Transmission 

Customer to seek redispatch with Transmission Providers in adjacent Control 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 57 

Areas. 

15.5 Deferral of Service: 

The Transmission Provider may defer providing service until it completes 

construction of new transmission facilities or upgrades needed to provide Firm 

Point-To-Point Transmission Service whenever the Transmission Provider 

determines that providing the requested service would, without such new 

facilities or upgrades, impair or degrade reliability to any existing firm 

services. 

15.6 Other Transmission Service Schedules: 

Eligible Customers receiving transmission service under other agreements on 

file with the Commission may continue to receive transmission service under 

those agreements until such time as those agreements may be modified by the 

Commission. 

15.7 Real Power Losses: 

Real Power Losses are associated with all transmission service. The 

Transmission Provider is not obligated to provide Real Power Losses. The 

Transmission Customer is responsible for replacing losses associated with all 

transmission service as calculated by the Transmission Provider. The 

applicable Real Power Loss factors are as follows: [To be completed by the 

Transmission Provider]. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 58 

16 Transmission Customer Responsibilities 

16.1 Conditions Required of Transmission Customers: 

Point-To-Point Transmission Service shall be provided by the Transmission 

Provider only if the following conditions are satisfied by the Transmission 

Customer: 

(a) The Transmission Customer has pending a Completed 

Application for service; 

(b) The Transmission Customer meets the creditworthiness criteria 

set forth in Section 11; 

(c) The Transmission Customer will have arrangements in place for 

any other transmission service necessary to effect the delivery 

from the generating source to the Transmission Provider prior to 

the time service under Part II of the Tariff commences; 

(d) The Transmission Customer agrees to pay for any facilities 

constructed and chargeable to such Transmission Customer under 

Part II of the Tariff, whether or not the Transmission Customer 

takes service for the full term of its reservation; 

(e) The Transmission Customer provides the information required by 

the Transmission Provider’s planning process established in 

Attachment K; and 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 59 

(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 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 60 

in which service is to commence. The Transmission Provider will consider 

requests for such firm service on shorter notice when feasible. Requests for 

firm service for periods of less than one year shall be subject to expedited 

procedures that shall be negotiated between the Parties within the time 

constraints provided in Section 17.5. All Firm Point-To-Point Transmission 

Service requests should be submitted by entering the information listed below 

on the Transmission Provider's OASIS. Prior to implementation of the 

Transmission Provider's OASIS, a Completed Application may be submitted 

by (i) transmitting the required information to the Transmission Provider by 

telefax, or (ii) providing the information by telephone over the Transmission 

Provider's time recorded telephone line. Each of these methods will provide a 

time-stamped record for establishing the priority of the Application. 

17.2 Completed Application: 

A Completed Application shall provide all of the information included in 18 

CFR  2.20 including but not limited to the following: 

(i) The identity, address, telephone number and facsimile number of 

the entity requesting service; 

(ii) A statement that the entity requesting service is, or will be upon 

commencement of service, an Eligible Customer under the Tariff; 

(iii) The location of the Point(s) of Receipt and Point(s) of Delivery 
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and the identities of the Delivering Parties and the Receiving 

Parties; 

(iv) The location of the generating facility(ies) supplying the capacity 

and energy and the location of the load ultimately served by the 

capacity and energy transmitted. The Transmission Provider will 

treat this information as confidential except to the extent that 

disclosure of this information is required by this Tariff, by 

regulatory or judicial order, for reliability purposes pursuant to 

Good Utility Practice or pursuant to RTG transmission 

information sharing agreements. The Transmission Provider shall 

treat this information consistent with the standards of conduct 

contained in Part 37 of the Commission's regulations; 

(v) A description of the supply characteristics of the capacity and 

energy to be delivered; 

(vi) An estimate of the capacity and energy expected to be delivered 

to the Receiving Party; 

(vii) The Service Commencement Date and the term of the requested 

Transmission Service; 

(viii) The transmission capacity requested for each Point of Receipt and 

each Point of Delivery on the Transmission Provider's 
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Transmission System; customers may combine their requests for 

service in order to satisfy the minimum transmission capacity 

requirement; 

(ix) A statement indicating whether the Transmission Customer 

commits to a Pre-Confirmed Request, i.e., will execute a Service 

Agreement upon receipt of notification that the Transmission 

Provider can provide the requested Transmission Service; and 

(x) Any additional information required by the Transmission 

Provider’s planning process established in Attachment K. 

The Transmission Provider shall treat this information consistent with the 

standards of conduct contained in Part 37 of the Commission's regulations. 

17.3 Deposit: 

A Completed Application for Firm Point-To-Point Transmission Service also 

shall include a deposit of either one month's charge for Reserved Capacity or 

the full charge for Reserved Capacity for service requests of less than one 

month. If the Application is rejected by the Transmission Provider because it 

does not meet the conditions for service as set forth herein, or in the case of 

requests for service arising in connection with losing bidders in a Request For 

Proposals (RFP), said deposit shall be returned with interest less any 

reasonable costs incurred by the Transmission Provider in connection with the 
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review of the losing bidder's Application. The deposit also will be returned 

with interest less any reasonable costs incurred by the Transmission Provider 

if the Transmission Provider is unable to complete new facilities needed to 

provide the service. If an Application is withdrawn or the Eligible Customer 

decides not to enter into a Service Agreement for Firm Point-To-Point 

Transmission Service, the deposit shall be refunded in full, with interest, less 

reasonable costs incurred by the Transmission Provider to the extent such 

costs have not already been recovered by the Transmission Provider from the 

Eligible Customer. The Transmission Provider will provide to the Eligible 

Customer a complete accounting of all costs deducted from the refunded 

deposit, which the Eligible Customer may contest if there is a dispute 

concerning the deducted costs. Deposits associated with construction of new 

facilities are subject to the provisions of Section 19. If a Service Agreement 

for Firm Point-To-Point Transmission Service is executed, the deposit, with 

interest, will be returned to the Transmission Customer upon expiration or 

termination of the Service Agreement for Firm Point-To-Point Transmission 

Service. Applicable interest shall be computed in accordance with the 

Commission's regulations at 18 CFR  35.19a(a)(2)(iii), and shall be calculated 

from the day the deposit check is credited to the Transmission Provider's 

account. 
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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 transmission capability as required in Section 15.2. The 

Transmission Provider shall notify the Eligible Customer as soon as 

practicable, but not later than thirty (30) days after the date of receipt of a 

Completed Application either (i) if it will be able to provide service without 

performing a System Impact Study or (ii) if such a study is needed to evaluate 

the impact of the Application pursuant to Section 19.1. Responses by the 
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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 

the commencement of service. The Transmission Customer may postpone 

service by paying a non-refundable annual reservation fee equal to one-
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month's charge for Firm Transmission Service for each year or fraction 

thereof. 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-ToPoint transmission rate for its Reserved Capacity concurrent with the new 

Service Commencement Date. In the event the Transmission Customer elects 

to release the Reserved Capacity, the reservation fees or portions thereof 

previously paid will be forfeited. 

18 Procedures for Arranging Non-Firm Point-To-Point Transmission 

Service 

18.1 Application: 

Eligible Customers seeking Non-Firm Point-To-Point Transmission Service 

must submit a Completed Application to the Transmission Provider. 

Applications should be submitted by entering the information listed below on 

the Transmission Provider's OASIS. Prior to implementation of the 

Transmission Provider's OASIS, a Completed Application may be submitted 

by (i) transmitting the required information to the Transmission Provider by 

telefax, or (ii) providing the information by telephone over the Transmission 
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Provider's time recorded telephone line. Each of these methods will provide a 

time-stamped record for establishing the service priority of the Application. 

18.2 Completed Application: 

A Completed Application shall provide all of the information included in 18 

CFR § 2.20 including but not limited to the following: 

(i) The identity, address, telephone number and facsimile number of 

the entity requesting service; 

(ii) A statement that the entity requesting service is, or will be upon 

commencement of service, an Eligible Customer under the Tariff; 

(iii) The Point(s) of Receipt and the Point(s) of Delivery; 

(iv) The maximum amount of capacity requested at each Point of 

Receipt and Point of Delivery; and 

(v) The proposed dates and hours for initiating and terminating 

transmission service hereunder. 

In addition to the information specified above, when required to properly 

evaluate system conditions, the Transmission Provider also may ask the 

Transmission Customer to provide the following: 

(vi) The electrical location of the initial source of the power to be 

transmitted pursuant to the Transmission Customer's request for 

service; and 
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(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

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 
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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 

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 
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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, 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 
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responsible for charges associated with any modifications to 

existing planning studies that are reasonably necessary to evaluate 

the impact of the Eligible Customer's request for service on the 

Transmission System. 

(ii) If in response to multiple Eligible Customers requesting service in 

relation to the same competitive solicitation, a single System 

Impact Study is sufficient for the Transmission Provider to 

accommodate the requests for service, the costs of that study shall 

be pro-rated among the Eligible Customers. 

(iii) For System Impact Studies that the Transmission Provider 

conducts on its own behalf, the Transmission Provider shall 

record the cost of the System Impact Studies pursuant to Section 

20. 

19.3 System Impact Study Procedures: 

Upon receipt of an executed System Impact Study Agreement, the 

Transmission Provider will use due diligence to complete the required System 

Impact Study within a sixty (60) day period. The System Impact Study shall 

identify any system constraints and redispatch options, including an estimate 

of the number of hours of redispatch that may be required to accommodate the 

request for Transmission Service and a preliminary estimate of the cost of 
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redispatch, 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. The Transmission Provider will use the same due diligence in 

completing the System Impact Study for an Eligible Customer as it uses when 

completing studies for itself. The Transmission Provider shall notify the 

Eligible Customer immediately upon completion of the System Impact Study 

if the Transmission System will be adequate to accommodate all or part of a 

request for service or that no costs are likely to be incurred for new 

transmission facilities or upgrades. In order for a request to remain a 

Completed Application, within fifteen (15) days of completion of the System 

Impact Study the Eligible Customer must execute a Service Agreement or 

request the filing of an unexecuted Service Agreement pursuant to Section 

15.3, or the Application shall be deemed terminated and withdrawn. 

19.4 Facilities Study Procedures: 

If a System Impact Study indicates that additions or upgrades to the 
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Transmission System are needed to supply the Eligible Customer's service 

request, the Transmission Provider, within thirty (30) days of the completion 

of the System Impact Study, shall tender to the Eligible Customer a Facilities 

Study Agreement pursuant to which the Eligible Customer shall agree to 

reimburse the Transmission Provider for performing the required Facilities 

Study. For a service request to remain a Completed Application, the Eligible 

Customer shall execute the Facilities Study Agreement and return it to the 

Transmission Provider within fifteen (15) days. If the Eligible Customer 

elects not to execute the Facilities Study Agreement, its application shall be 

deemed withdrawn and its deposit, pursuant to Section 17.3, shall be returned 

with interest. Upon receipt of an executed Facilities Study Agreement, the 

Transmission Provider will use due diligence to complete the required 

Facilities Study within a sixty (60) day period. If the Transmission Provider is 

unable to complete the Facilities Study in the allotted time period, the 

Transmission Provider shall notify the Transmission Customer and provide an 

estimate of the time needed to reach a final determination along with an 

explanation of the reasons that additional time is required to complete the 

study. When completed, the Facilities Study will include a good faith estimate 

of (i) the cost of Direct Assignment Facilities to be charged to the 

Transmission Customer, (ii) the Transmission Customer's appropriate share of 
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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 

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 
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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 

been placed in service. 

19.8 Expedited Procedures for New Facilities: 
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In lieu of the procedures set forth above, the Eligible Customer shall have the 

option to expedite the process by requesting the Transmission Provider to 

tender at one time, together with the results of required studies, an "Expedited 

Service Agreement" pursuant to which the Eligible Customer would agree to 

compensate the Transmission Provider for all costs incurred pursuant to the 

terms of the Tariff. In order to exercise this option, the Eligible Customer 

shall request in writing an expedited Service Agreement covering all of the 

above-specified items within thirty (30) days of receiving the results of the 

System Impact Study identifying needed facility additions or upgrades or costs 

incurred in providing the requested service. While the Transmission Provider 

agrees to provide the Eligible Customer with its best estimate of the new 

facility costs and other charges that may be incurred, such estimate shall not 

be binding and the Eligible Customer must agree in writing to compensate the 

Transmission Provider for all costs incurred pursuant to the provisions of the 

Tariff. The Eligible Customer shall execute and return such an Expedited 

Service Agreement within fifteen (15) days of its receipt or the Eligible 

Customer's request for service will cease to be a Completed Application and 

will be deemed terminated and withdrawn. 

19.9 Penalties for Failure to Meet Study Deadlines: 
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Sections 19.3 and 19.4 require a Transmission Provider to use due diligence to 

meet 60-day study completion deadlines for System Impact Studies and 

Facilities Studies. 

(i) The Transmission Provider is required to file a notice with the 

Commission in the event that more than twenty (20) percent of 

non-Affiliates’ System Impact Studies and Facilities Studies 

completed by the Transmission Provider in any two consecutive 

calendar quarters are not completed within the 60-day study 

completion deadlines. Such notice must be filed within thirty (30) 

days of the end of the calendar quarter triggering the notice 

requirement. 

(ii) For the purposes of calculating the percent of non-Affiliates’ 

System Impact Studies and Facilities Studies processed outside of 

the 60-day study completion deadlines, the Transmission Provider 

shall consider all System Impact Studies and Facilities Studies 

that it completes for non-Affiliates during the calendar quarter. 

The percentage should be calculated by dividing the number of 

those studies which are completed on time by the total number of 

completed studies. The Transmission Provider may provide an 

explanation in its notification filing to the Commission if it 
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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 

Provider takes to complete that study beyond the 60-day deadline. 
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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 

construction of the alternative facilities, it may request the Transmission 
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Provider to submit a revised Service Agreement for Firm Point-To-Point 

Transmission Service. If the alternative approach solely involves Non-Firm 

Point-To-Point Transmission Service, the Transmission Provider shall 

promptly tender a Service Agreement for Non-Firm Point-To-Point 

Transmission Service providing for the service. In the event the Transmission 

Provider concludes that no reasonable alternative exists and the Transmission 

Customer disagrees, the Transmission Customer may seek relief under the 

dispute resolution procedures pursuant to Section 12 or it may refer the 

dispute to the Commission for resolution. 

20.3 Refund Obligation for Unfinished Facility Additions: 

If the Transmission Provider and the Transmission Customer mutually agree 

that no other reasonable alternatives exist and the requested service cannot be 

provided out of existing capability under the conditions of Part II of the Tariff, 

the obligation to provide the requested Firm Point-To-Point Transmission 

Service shall terminate and any deposit made by the Transmission Customer 

shall be returned with interest pursuant to Commission regulations 

35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible 

for all prudently incurred costs by the Transmission Provider through the time 

construction was suspended. 

21 Provisions Relating to Transmission Construction and Services on the 
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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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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 that are Affiliates of the Transmission Provider shall not exceed the 

higher of (i) the original rate paid by the Reseller, (ii) the Transmission 

Provider's maximum rate on file at the time of the assignment, or (iii) the 

Reseller's opportunity cost capped at the Transmission Provider's cost of 

expansion. Compensation to Resellers that are not Affiliates of the 

Transmission Provider shall be at rates established by agreement with the 

Assignee. If the Assignee does not request any change in the Point(s) of 

Receipt or the Point(s) of Delivery, or a change in any other term or condition 
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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. A Reseller should notify the Transmission 

Provider as soon as possible after any assignment or transfer of service occurs 

but in any event, notification must be provided prior to any provision of 

service to the Assignee. 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 
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Service Agreement, except as specifically agreed to by the Parties through an 

amendment to the Service Agreement. 

23.3 Information on Assignment or Transfer of Service: 

In accordance with Section 4, Resellers may 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 87 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 88 

identifies capacity constraints that may be relieved more economically by 

redispatching the Transmission Provider's resources than by building new facilities 

or upgrading existing facilities 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: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 89 

Network Integration Transmission Service is a transmission service that 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 90 

service sufficient transfer capability to deliver the Network Customer's 

Network Resources to serve its Network Load on a basis comparable to the 

Transmission Provider's delivery of its own generating and purchased 

resources to its Native Load Customers. 

28.3 Network Integration Transmission Service: 

The Transmission Provider will provide firm transmission service over its 

Transmission System to the Network Customer for the delivery of capacity 

and energy from its designated Network Resources to service its Network 

Loads on a basis that is comparable to the Transmission Provider's use of the 

Transmission System to reliably serve its Native Load Customers. 

28.4 Secondary Service: 

The Network Customer may use the Transmission Provider's Transmission 

System to deliver Economy 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 91 

Part II of the Tariff. 

28.5 Real Power Losses: 

Real Power Losses are associated with all transmission service. The 

Transmission Provider is not obligated to provide Real Power Losses. The 

Network Customer is responsible for replacing losses associated with all 

transmission service as calculated by the Transmission Provider. The 

applicable Real Power Loss factors are as follows: [To be completed by the 

Transmission Provider]. 

28.6 Restrictions on Use of Service: 

The Network Customer shall not use Network Integration Transmission 

Service for (i) sales of capacity and energy to non-designated loads, or (ii) 

direct or indirect provision of transmission service by the Network Customer 

to third parties. All Network Customers taking Network Integration 

Transmission Service shall use 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. 

29 Initiating Service 

29.1 Condition Precedent for Receiving Service: 

Subject to the terms and conditions of Part III of the Tariff, the Transmission 

Provider will provide Network Integration Transmission Service to any 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 92 

Eligible Customer, provided that (i) the Eligible Customer completes an 

Application for service as provided under Part III of the Tariff, (ii) the Eligible 

Customer and the Transmission Provider complete the technical arrangements 

set forth in Sections 29.3 and 29.4, (iii) the Eligible Customer executes a 

Service Agreement pursuant to Attachment F for service under Part III of the 

Tariff or requests in writing that the Transmission Provider file a proposed 

unexecuted Service Agreement with the Commission, and (iv) the Eligible 

Customer executes a Network Operating Agreement with the Transmission 

Provider pursuant to Attachment G, or requests in writing that the 

Transmission Provider file a proposed unexecuted Network Operating 

Agreement. 

29.2 Application Procedures: 

An Eligible Customer requesting service under Part III of the Tariff must 

submit an Application, with a deposit approximating the charge for one month 

of service, to the Transmission Provider as far as possible in advance of the 

month in which service is to commence. Unless subject to the procedures in 

Section 2, Completed Applications for Network Integration Transmission 

Service will be assigned a priority according to the date and time the 

Application is received, with the earliest Application receiving the highest 

priority. Applications should be submitted by entering the information listed 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 93 

below on the Transmission Provider's OASIS. Prior to implementation of the 

Transmission Provider's OASIS, a Completed Application may be submitted 

by (i) transmitting the required information to the Transmission Provider by 

telefax, or (ii) providing the information by telephone over the Transmission 

Provider's time recorded telephone line. Each of these methods will provide a 

time-stamped record for establishing the service priority of the Application. A 

Completed Application shall provide all of the information included in 18 

CFR § 2.20 including but not limited to the following: 

(i) The identity, address, telephone number and facsimile number of 

the party requesting service; 

(ii) A statement that the party requesting service is, or will be upon 

commencement of service, an Eligible Customer under the Tariff; 

(iii) A description of the Network Load at each delivery point. This 

description should separately identify and provide the Eligible 

Customer's best estimate of the total loads to be served at each 

transmission voltage level, and the loads to be served from each 

Transmission Provider substation at the same transmission 

voltage level. The description should include a ten (10) year 

forecast of summer and winter load and resource requirements 

beginning with the first year after the service is scheduled to 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 94 

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), which shall include, for each Network Resource: 

• Unit size and amount of capacity from that unit to be 

designated as Network Resource 

• VAR capability (both leading and lagging) of all generators 

• Operating restrictions 

− Any periods of restricted operations throughout the year 

− Maintenance schedules 

− Minimum loading level of unit 

− Normal operating level of unit 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 95 

− 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 

• Description of purchased power designated as a Network 

Resource including source of supply, Control Area location, 

transmission arrangements and delivery point(s) to the 

Transmission Provider's Transmission System; 

(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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 96 

• 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 97 

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 

Customers 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 98 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 99 

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: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 100 

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 at any time but should provide 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 101 

notification to the Transmission Provider through OASIS as soon as 

reasonably practicable. 

30.4 Operation of Network Resources: 

The Network Customer shall not operate its designated Network Resources 

located in the Network Customer's or Transmission Provider's Control Area 

such that the output of those facilities exceeds its designated Network Load, 

plus Non-Firm Sales delivered pursuant to Part II of the Tariff, plus losses. 

This limitation shall not apply to changes in the operation of a Transmission 

Customer's Network Resources at the request of the Transmission Provider to 

respond to an emergency or other unforeseen condition which may impair or 

degrade the reliability of the Transmission System. The Network Customer 

may not schedule delivery of a Network Resource not physically 

interconnected with the Transmission Provider’s Transmission System in 

excess of the Network Resource’s capacity, as specified in the Network 

Customer’s Application pursuant to Section 29. 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 Point of Delivery for a 

Network Resource not physically interconnected with the Transmission 

Provider's Transmission System exceeds the Network Resource’s designated 

capacity. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 102 

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 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 103 

Customer may establish that execution of a contract is contingent upon the 

availability of transmission service under Part III of the Tariff. 

30.8 Use of Interface Capacity by the Network Customer: 

There is no limitation upon a Network Customer's use of the Transmission 

Provider's Transmission System at any particular interface to integrate the 

Network Customer's Network Resources (or substitute economy purchases) 

with its Network Loads. However, a Network Customer's use of the 

Transmission Provider's total interface capacity with other transmission 

systems may not exceed the Network Customer's Load. 

30.9 Network Customer Owned Transmission Facilities: 

The Network Customer that owns existing transmission facilities that are 

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 provided such facilities are integrated into the operations 

of the Transmission Provider's facilities and, if the transmission facilities were 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 104 

owned by the Transmission Provider, would be eligible for inclusion in the 

Transmission Provider’s Annual Transmission Revenue Requirement. 

Calculation of any credit under this subsection shall be addressed in either the 

Network Customer's Service Agreement or any other agreement between the 

Parties. 

31 Designation of Network Load 

31.1 Network Load: 

The Network Customer must designate the individual Network Loads on 

whose behalf the Transmission Provider will provide Network Integration 

Transmission Service. The Network Loads shall be specified in the Service 

Agreement. 

31.2 New Network Loads Connected With the Transmission Provider: 

The Network Customer shall provide the Transmission Provider with as much 

advance notice as reasonably practicable of the designation of new Network 

Load that will be added to its Transmission System. A designation of new 

Network Load must be made through a modification of service pursuant to a 

new Application. The Transmission Provider will use due diligence to install 

any transmission facilities required to interconnect a new Network Load 

designated by the Network Customer. The costs of new facilities required to 

interconnect a new Network Load shall be determined in accordance with the 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 105 

procedures provided in Section 32.4 and shall be charged to the Network 

Customer in accordance with Commission policies. 

31.3 Network Load Not Physically Interconnected with the Transmission 

Provider: 

This section applies to both initial designation pursuant to Section 31.1 and 

the subsequent addition of new Network Load not physically interconnected 

with the Transmission Provider. To the extent that the Network Customer 

desires to obtain transmission service for a load outside the Transmission 

Provider's Transmission System, the Network Customer shall have the option 

of (1) electing to include the entire load as Network Load for all purposes 

under Part III of the Tariff and designating Network Resources in connection 

with such additional Network Load, or (2) excluding that entire load from its 

Network Load and purchasing Point-To-Point Transmission Service under 

Part II of the Tariff. To the extent that the Network Customer gives notice of 

its intent to add a new Network Load as part of its Network Load pursuant to 

this section the request must be made through a modification of service 

pursuant to a new Application. 

31.4 New Interconnection Points: 

To the extent the Network Customer desires to add a new Delivery Point or 

interconnection point between the Transmission Provider's Transmission 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 106 

System and a Network Load, the Network Customer shall provide the 

Transmission Provider with as much advance notice as reasonably practicable. 

31.5 Changes in Service Requests: 

Under no circumstances shall the Network Customer's decision to cancel or 

delay a requested change in Network Integration Transmission Service (e.g.

the addition of a new Network Resource or designation of a new Network 

Load) in any way relieve the Network Customer of its obligation to pay the 

costs of transmission facilities constructed by the Transmission Provider and 

charged to the Network Customer as reflected in the Service Agreement. 

However, the Transmission Provider must treat any requested change in 

Network Integration Transmission Service in a 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 107 

Network Customer's Network Load, Network Resources, its transmission 

system or other aspects of its facilities or operations affecting the 

Transmission Provider's ability to provide reliable service. 

32 Additional Study Procedures For Network Integration Transmission 

Service Requests 

32.1 Notice of Need for System Impact Study: 

After receiving a request for service, the Transmission Provider shall 

determine on a non-discriminatory basis whether a System Impact Study is 

needed. A description of the Transmission Provider's methodology for 

completing a System Impact Study is provided in Attachment D. If the 

Transmission Provider determines that a System Impact Study is necessary to 

accommodate the requested service, it shall so inform the Eligible Customer, 

as soon as practicable. In such cases, the Transmission Provider shall within 

thirty (30) days of receipt of a Completed Application, tender a System Impact 

Study Agreement pursuant to which the Eligible Customer shall agree to 

reimburse the Transmission Provider for performing the required System 

Impact Study. For a service request to remain a Completed Application, the 

Eligible Customer shall execute the System Impact Study Agreement and 

return it to the Transmission Provider within fifteen (15) days. If the Eligible 

Customer elects not to execute the System Impact Study Agreement, its 

Application shall be deemed withdrawn and its deposit shall be returned with 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 108 

interest. 

32.2 System Impact Study Agreement and Cost Reimbursement: 

(i) The System Impact Study Agreement will clearly specify the 

Transmission Provider's estimate of the actual cost, and time for 

completion of the System Impact Study. The charge shall not 

exceed the actual cost of the study. In performing the System 

Impact Study, the Transmission Provider shall rely, to the extent 

reasonably practicable, on existing transmission planning studies. 

The Eligible Customer will not be assessed a charge for such 

existing studies; however, the Eligible 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 109 

conducts on its own behalf, the Transmission Provider shall 

record the cost of the System Impact Studies pursuant to Section 

8. 

32.3 System Impact Study Procedures: 

Upon receipt of an executed System Impact Study Agreement, the 

Transmission Provider will use due diligence to complete the required System 

Impact Study within a sixty (60) day period. The System Impact Study shall 

identify any system constraints and redispatch options, including an estimate 

of the number of hours of redispatch that may be required to accommodate the 

request for Transmission Service and a preliminary estimate of the cost of 

redispatch, 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. 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 110 

Eligible Customer immediately upon completion of the System Impact Study 

if the Transmission System will be adequate to accommodate all or part of a 

request for service or that no costs are likely to be incurred for new 

transmission facilities or upgrades. In order for a request to remain a 

Completed Application, within fifteen (15) days of completion of the System 

Impact Study the Eligible Customer must execute a Service Agreement or 

request the filing of an unexecuted Service Agreement, or the Application 

shall be deemed terminated and withdrawn. 

32.4 Facilities Study Procedures: 

If a System Impact Study indicates that additions or upgrades to the 

Transmission System are needed to supply the Eligible Customer's service 

request, the Transmission Provider, within thirty (30) days of the completion 

of the System Impact Study, shall tender to the Eligible Customer a Facilities 

Study Agreement pursuant to which the Eligible Customer shall agree to 

reimburse the Transmission Provider for performing the required Facilities 

Study. For a service request to remain a Completed Application, the Eligible 

Customer shall execute the Facilities Study Agreement and return it to the 

Transmission Provider within fifteen (15) days. If the Eligible Customer 

elects not to execute the Facilities Study Agreement, its Application shall be 

deemed withdrawn and its deposit shall be returned with interest. Upon 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 111 

receipt of an executed Facilities Study Agreement, the Transmission Provider 

will use due diligence to complete the required Facilities Study within a sixty 

(60) day period. If the Transmission Provider is unable to complete the 

Facilities Study in the allotted time period, the Transmission Provider shall 

notify the Eligible Customer and provide an estimate of the time needed to 

reach a final determination along with an explanation of the reasons that 

additional time is required to complete the study. When completed, the 

Facilities Study will include a good faith estimate of (i) the cost of Direct 

Assignment Facilities to be charged to the Eligible Customer, (ii) the Eligible 

Customer's appropriate share of the cost of any required Network Upgrades, 

and (iii) the time required to complete such construction and initiate the 

requested service. The Eligible Customer shall provide the Transmission 

Provider with a letter of credit or other reasonable form of security acceptable 

to the Transmission Provider equivalent to the costs of new facilities or 

upgrades consistent with commercial practices as established by the Uniform 

Commercial Code. The Eligible Customer shall have thirty (30) days to 

execute a Service Agreement or request the filing of an unexecuted Service 

Agreement and provide the required letter of credit or other form of security 

or the request no longer will be a Completed Application and shall be deemed 

terminated and withdrawn. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 112 

32.5 Penalties for Failure to Meet Study Deadlines: 

Section 19.9 defines penalties that apply for failure to meet the 60-day study 

completion due diligence deadlines for System Impact Studies and Facilities 

Studies under Part II of the Tariff. These same requirements and penalties 

apply to service under Part III of the Tariff. 

33 Load Shedding and Curtailments 

33.1 Procedures: 

Prior to the Service Commencement Date, the Transmission Provider and the 

Network Customer shall establish Load Shedding and Curtailment procedures 

pursuant to the Network Operating Agreement with the objective of 

responding to contingencies on the Transmission System and on systems 

directly and indirectly interconnected with Transmission Provider’s 

Transmission System. The Parties will implement such programs during any 

period when the Transmission Provider determines that a system contingency 

exists and such procedures are necessary to alleviate such contingency. The 

Transmission Provider will notify all affected Network Customers in a timely 

manner of any scheduled Curtailment. 

33.2 Transmission Constraints: 

During any period when the Transmission Provider determines that a 

transmission constraint exists on the Transmission System, and such constraint 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 113 

may impair the reliability of the Transmission Provider's system, the 

Transmission Provider will take whatever actions, consistent with Good 

Utility Practice, that are reasonably necessary to maintain the reliability of the 

Transmission Provider's system. To the extent the Transmission Provider 

determines that the reliability of the Transmission System can be maintained 

by redispatching resources, the Transmission Provider will initiate procedures 

pursuant to the Network Operating Agreement to redispatch all Network 

Resources and the Transmission Provider's own resources on a least-cost basis 

without regard to the ownership of such resources. Any redispatch under this 

section may not unduly discriminate between the Transmission Provider's use 

of the Transmission System on behalf of its Native Load Customers and any 

Network Customer's use of the Transmission System to serve its designated 

Network Load. 

33.3 Cost Responsibility for Relieving Transmission Constraints: 

Whenever the Transmission Provider implements least-cost redispatch 

procedures in response to a transmission constraint, the Transmission Provider 

and Network 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 114 

System cannot be relieved through the implementation of least-cost redispatch 

procedures and the Transmission Provider determines that it is necessary to 

Curtail scheduled deliveries, the Parties shall Curtail such schedules in 

accordance with the Network Operating Agreement or pursuant to the 

Transmission Loading Relief procedures specified in Attachment J. 

33.5 Allocation of Curtailments: 

The Transmission Provider shall, on a non-discriminatory basis, Curtail the 

transaction(s) that effectively relieve the constraint. However, to the extent 

practicable and consistent with Good Utility Practice, any Curtailment will be 

shared by the Transmission Provider and Network Customer in proportion to 

their respective Load Ratio Shares. The Transmission Provider shall not 

direct the Network Customer to Curtail schedules to an extent greater than the 

Transmission Provider would Curtail the Transmission Provider's schedules 

under similar circumstances. 

33.6 Load Shedding: 

To the extent that a system contingency exists on the Transmission Provider's 

Transmission System and the Transmission Provider determines that it is 

necessary for the Transmission Provider and the Network Customer to shed 

load, the Parties shall shed load in accordance with previously established 

procedures under the Network Operating Agreement. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 115 

33.7 System Reliability: 

Notwithstanding any other provisions of this Tariff, the Transmission Provider 

reserves the right, consistent with Good Utility Practice and on a not unduly 

discriminatory basis, to Curtail Network Integration Transmission Service 

without liability on the Transmission Provider's part for the purpose of making 

necessary adjustments to, changes in, or repairs on its lines, substations and 

facilities, and in cases where the continuance of Network Integration 

Transmission Service would endanger persons or property. In the event of 

any adverse condition(s) or disturbance(s) on the Transmission Provider's 

Transmission System or on any other system(s) directly or indirectly 

interconnected with the Transmission Provider's Transmission System, the 

Transmission Provider, consistent with Good Utility Practice, also may Curtail 

Network Integration Transmission Service in order to (i) limit the extent or 

damage of the adverse condition(s) or disturbance(s), (ii) prevent damage to 

generating or transmission facilities, or (iii) expedite restoration of service. 

The Transmission Provider will give the Network Customer as much advance 

notice as is practicable in the event of such Curtailment. Any Curtailment of 

Network Integration Transmission Service will be not unduly discriminatory 

relative to the Transmission Provider's use of the Transmission System on 

behalf of its Native Load Customers. The Transmission Provider shall specify 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 116 

the rate treatment and all related terms and conditions applicable in the event 

that the Network Customer fails to respond to established Load Shedding and 

Curtailment procedures. 

34 Rates and Charges 

 The Network Customer shall pay the Transmission Provider for any Direct 

Assignment Facilities, Ancillary Services, and applicable study costs, consistent 

with Commission policy, along with the following: 

34.1 Monthly Demand Charge: 

The Network Customer shall pay a monthly Demand Charge, which shall be 

determined by multiplying its Load Ratio Share times one twelfth (1/12) of the 

Transmission Provider's Annual Transmission Revenue Requirement specified 

in Schedule H. 

34.2 Determination of Network Customer's Monthly Network Load: 

The Network Customer's monthly Network Load is its hourly load (including 

its designated Network Load not physically interconnected with the 

Transmission Provider under Section 31.3) coincident with the Transmission 

Provider's Monthly Transmission System Peak. 

34.3 Determination of Transmission Provider's Monthly Transmission 

System Load: 

The Transmission Provider's monthly Transmission System load is the 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 117 

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: 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 118 

in accordance with Good Utility Practice and in conformance with the 

Network Operating Agreement. 

35.2 Network Operating Agreement: 

The terms and conditions under which the Network Customer shall operate its 

facilities and the technical and operational matters associated with the 

implementation of Part III of the Tariff shall be specified in the Network 

Operating Agreement. The Network Operating Agreement shall provide for 

the Parties to (i) operate and maintain equipment necessary for integrating the 

Network Customer within the Transmission Provider's Transmission System 

(including, but not limited to, remote terminal units, metering, 

communications equipment and relaying equipment), (ii) transfer data 

between the Transmission Provider and the Network Customer (including, but 

not limited to, heat rates and operational characteristics of Network Resources, 

generation schedules for units outside the Transmission Provider's 

Transmission System, interchange schedules, unit outputs for redispatch 

required under Section 33, voltage schedules, loss factors and other real time 

data), (iii) use software programs required for data links and constraint 

dispatching, (iv) exchange data on forecasted loads and resources necessary 

for long-term planning, and (v) address any other technical and operational 

considerations required for implementation of Part III of the Tariff, including 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 119 

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 North American Electric Reliability Council 

(NERC) and the [applicable regional reliability council], (ii) satisfy its Control 

Area requirements, including all necessary Ancillary Services, by contracting 

with the Transmission Provider, or (iii) satisfy its Control Area requirements, 

including all necessary Ancillary Services, by contracting with another entity, 

consistent with Good Utility Practice, which satisfies NERC and the 

[applicable regional reliability council] requirements. 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 120 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 121 

SCHEDULE 2 

Reactive Supply and Voltage Control from 

Generation Sources Service 

 In order to maintain transmission voltages on the Transmission Provider's 

transmission facilities within acceptable limits, generation facilities under the control of 

the control area operator are operated to produce (or absorb) reactive power. Thus, 

Reactive Supply and Voltage Control from Generation 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 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 Sources Service is to be 

provided directly by the Transmission Provider (if the Transmission Provider is the 

Control Area operator) or indirectly by the Transmission Provider making arrangements 

with the Control Area operator that performs this service for the Transmission Provider's 

Transmission System. The Transmission Customer must purchase this service from the 

Transmission Provider or the Control Area operator. The charges for such service will be 

based on the rates set forth below. To the extent the Control Area operator performs this 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 122 

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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 123 

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) 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 124 

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 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 only charge a Transmission Customer 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 a deviation band of +/- 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). Parties should attempt to eliminate energy imbalances within the limits of 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 125 

the deviation band within thirty (30) days or within such other reasonable period of time 

as is generally accepted in the region and consistently adhered to by the Transmission 

Provider. If an energy imbalance is not corrected within thirty (30) days or a reasonable 

period of time that is generally accepted in the region and consistently adhered to by the 

Transmission Provider, the Transmission Customer will compensate the Transmission 

Provider for such service. Energy imbalances outside the deviation band will be subject 

to charges to be specified by the Transmission Provider. The charges for Energy 

Imbalance Service are set forth below. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 126 

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. 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 127 

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. 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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 128 

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) Hourly delivery: $ /KW of Reserved Capacity per hour. 

The total demand charge in any day, pursuant to a reservation for Hourly delivery, 

shall not exceed the rate specified in section (4) 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 (3) 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. 129 

6) 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. 130 

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. 131 

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. 132 

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 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 

only charge a Transmission Customer 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 a deviation band of +/- 1.5 percent (with 

a minimum of 2 MW) of the scheduled transaction to be applied on a net hourly basis to 

any Generator Imbalance that occurs as a result of the Transmission Customer's 

scheduled transaction(s). The charges for Generator Imbalance Service are set out below: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 133 

 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. 134 

 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. 135 

 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. 136 

 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 8.4 Ancillary Services Charges: ______________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 137 

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. 138 

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. 139 

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) 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 (e.g., load flow, short circuit, stability, transfer 

studies); (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, 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 

explain: (i) its definition of AFC; (ii) its AFC calculation methodology (e.g., load flow, 

short circuit, stability, transfer studies); (iii) its process for converting AFC into ATC; 

(iv) what databases are used in its AFC assessments; (v) the assumptions used in its AFC 

assessments; and (vi) the reliability criteria used for contingency outages simulation. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 140 

(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; and (v) the process used to prevent double-counting of contingency 

outages used in its TTC and TRM calculations. A Transmission Provider that does not 

reserve 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) who performs the 

assessment (transmission or merchant staff); (ii) the methodology used to perform 

generation reliability assessments (e.g., probabilistic or deterministic); (iii) whether the 

assessment method reflects a specific regional practice; (iv) the assumptions used in those 

assessments; 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) prove that there is no 

double-counting of contingency outages when performing CBM, TTC, and TRM 

calculations. 

(g) The Transmission Provider shall post its procedures for allowing CBM during 

emergencies (with an explanation of what constitutes an emergency, the entities that are 

permitted to use CBM during emergencies and the procedures which must be followed by 

the transmission providers’ merchant function and other load-serving entities when they 

need to access CBM). If the Transmission Provider’s practice is not to reserve CBM, it 

shall so state. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 141 

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. 142 

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. 143 

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. 144 

ATTACHMENT G 

Network Operating Agreement 

 To be filed by the Transmission Provider 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 145 

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. 146 

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. 147 

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. 148 

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 eight 

principles, as defined in the Final Rule in Docket No. RM05-25-000: coordination, 

openness, transparency, information exchange, comparability, dispute resolution, regional 

coordination, and congestion studies. 

 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 149 

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.