121 FERC ¶ 61,297 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 37 

(Docket Nos. RM05-17-001, 002 and RM05-25-001, 002; Order No. 890-A) 

Preventing Undue Discrimination and Preference in Transmission Service 

(Issued December 28, 2007) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Order on Rehearing and Clarification 

SUMMARY: The Federal Energy Regulatory Commission affirms its basic 

determinations in Order No. 890, granting rehearing and clarification regarding certain 

revisions to its regulations and the pro forma open-access transmission tariff, or OATT, 

adopted in Order Nos. 888 and 889 to ensure that transmission services are provided on a 

basis that is just, reasonable, and not unduly discriminatory. The reforms affirmed in this 

order are designed to: (1) strengthen the pro forma OATT to ensure that it achieves its 

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

reduce opportunities for undue discrimination and facilitate the Commission’s 

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

the transmission system. 

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

publication in the FEDERAL REGISTER]
Docket No. RM05-17-001, et al. - 2 -

FOR FURTHER INFORMATION CONTACT: 

W. Mason Emnett (Legal Information) 

Office of the General Counsel – Energy Markets 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6540 

Daniel Hedberg (Technical Information) 

Office of Energy Market Regulation 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6243 

Tony Ingram (Technical Information) 

Office of Energy Market Regulation 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-8938 

SUPPLEMENTARY INFORMATION

:
TABLE OF CONTENTS

 Paragraph Numbers

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

II. NEED FOR AND APPLICABILITY OF ORDER NO. 888.................................. 7.

A. The Need for Reform ............................................................................................... 7.

B. Core Elements of Order No. 888 that are Retained................................................ 17.

C. Scope and Applicability of Order No. 890............................................................. 25.

III. REFORMS OF THE OATT ................................................................................. 39.

A. Consistency and Transparency of ATC Calculations ........................................... 39.

B. Coordinated, Open, and Transparent Planning .................................................... 153.

C. Transmission Pricing............................................................................................ 265.

1. Energy and Generation Imbalances.................................................................. 265.

2. Credits for Network Customers........................................................................ 334.

3. Capacity Reassignment..................................................................................... 374.

4. “Operational” Penalties ................................................................................... 434.

5. “Higher of” Pricing Policy ............................................................................... 487.

6. Other Ancillary Services .................................................................................. 494.

D. Non-Rate Terms and Conditions.......................................................................... 507.

1. Modifications to Long Term Firm Point-to-Point Service............................... 507.

2. Rollover Rights................................................................................................. 632.

3. Modification of Receipt or Delivery Points .................................................... 697.

4. Acquisition of Transmission Service................................................................ 709.

5. Designation of Network Resources .................................................................. 821.

6. Clarifications Related to Network Service ....................................................... 952.

7. Transmission Curtailments ............................................................................... 973.

8. Standardization of Rules and Practices ............................................................ 979.

9. OATT Definitions............................................................................................. 998.

E. Enforcement........................................................................................................ 1025.
Docket No. RM05-17-001, et al. - ii - 

IV. INFORMATION COLLECTION STATEMENT........................................... 1044.

V. DOCUMENT AVAILABILITY.......................................................................... 1045.

VI. EFFECTIVE DATE AND CONGRESSIONAL NOTIFICATION .............. 1048.

APPENDIX A: Petitioner Acronyms 

APPENDIX B: Post-Technical Conference Commenter Acronyms 

APPENDIX C: Pro Forma Open Access Transmission Tariff 
121 FERC ¶ 61,297 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Preventing Undue Discrimination and Preference in 

Transmission Service 

Docket Nos. RM05-17-001 

RM05-17-002 

RM05-25-001 

RM05-25-002 

ORDER NO. 890-A 

ORDER ON REHEARING AND CLARIFICATION 

(Issued December 28, 2007)

I. Introduction

1. On February 16, 2007, the Commission issued Order No. 890,1

 addressing and 

remedying opportunities for undue discrimination under the pro forma Open Access 

Transmission Tariff (OATT) adopted in Order No. 888.2

 The pro forma OATT was 

 1

 Preventing Undue Discrimination and Preference in Transmission Service, Order 

No. 890, 72 FR 12,266 (March 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007) (Order 

No. 890). 

2

 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 

 (continued...) 
Docket No. RM05-17-001, et al. - 2 -

intended to foster greater competition in wholesale power markets by reducing barriers to 

entry in the provision of transmission service. In the ten years since Order No. 888, 

however, flaws in the pro forma OATT undermined its ability to realize the core 

objective of remedying undue discrimination. The Commission acted in Order No. 890 

to correct these flaws by reforming the terms and conditions of the pro forma OATT in 

several critical areas, including the calculation of available transfer capability (ATC), the 

planning of transmission facilities, and the conditions of services offered by each 

transmission provider. 

2. Many have expressed support of the Commission’s reforms. Greater specificity 

regarding the transmission provider’s obligations under its OATT will reduce 

opportunities for the exercise of undue discrimination, make undue discrimination easier 

to detect, and facilitate the Commission’s enforcement of the tariff. Greater transparency 

in the rules applicable to the planning and use of the transmission system will help both 

transmission providers and customers comply with applicable tariff requirements. 

Although we grant rehearing and clarification below to address certain implementation 

issues raised by petitioners, we leave in place the fundamental reforms adopted in Order 

No. 890. 

3. At the outset, we note that work is well underway to develop consistent practices 

governing the calculation of ATC, in coordination with the North American Electric 

 

(D.C. Cir. 2000) (TAPS v. FERC), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002). 
Docket No. RM05-17-001, et al. - 3 -

Reliability Corporation (NERC) and the North American Energy Standards Board 

(NAESB). Eliminating the broad discretion that transmission providers currently have in 

calculating ATC will increase nondiscriminatory access to the grid and ensure that 

customers are treated fairly in seeking alternative power supplies. We commend 

transmission providers for the substantial resources they have dedicated to this process 

and NERC and NAESB for their leadership in guiding the standardization effort. 

4. We also commend transmission providers for the substantial resources dedicated 

to the development of transmission planning processes in response to Order No. 890. 

Transmission providers and stakeholders recently submitted tariff proposals that will 

govern transmission planning under the pro forma OATT. Transmission planning is 

critical because it is the means by which customers consider and access new sources of 

energy and have an opportunity to explore the feasibility of non-transmission alternatives. 

It is therefore vital for each transmission provider to open its transmission planning 

process to customers, coordinate with customers regarding future system plans, and share 

necessary planning information with customers. 

5. In addition, transmission providers have implemented new service options for 

long-term firm point-to-point customers and adopted modifications to other services. 

Instead of denying a long-term request for point-to-point service because as little as one 

hour of service is unavailable, transmission providers must now consider their ability to 

offer a modified form of planning redispatch or a new conditional firm option to 

accommodate the request. This increases opportunities to efficiently utilize transmission 

by eliminating artificial barriers to use of the grid. Charges for energy and generation 
Docket No. RM05-17-001, et al. - 4 -

imbalances also have been standardized, including relaxed penalties for intermittent 

resources. This standardization reduces the potential for undue discrimination, increases 

transparency, and reduces confusion in the industry that resulted from the prior lack of 

consistency. 

6. Taken together, these and other reforms adopted in Order No. 890 will better 

enable the pro forma OATT to achieve the core object of remedying undue 

discrimination in the provision of transmission service. The Commission therefore 

rejects requests to eliminate, or substantially modify, the various reforms adopted in 

Order No. 890.3

 We address each of the arguments made by petitioners in turn. We also 

address comments received in response to the technical conference held by Commission 

staff on July 30, 2007, regarding certain issues related to the designation and termination 

of network resources, in section III.D.5.4

 3

 A list of petitioners filing requests for rehearing and/or clarification is provided 

in Appendix A. The requests for rehearing filed by American Transmission, Bonneville, 

EPSA, Pacific Northwest Parties, and REPIO are deficient because they fail to include a 

Statement of Issues section separate from the arguments made, as required by Rule 713 

of the Commission’s Rules of Practice and Procedure. See 18 CFR 385.713(c)(2). 

Consistent with Rule 713, we deem these petitioners to have waived the particular issues 

for which they seek rehearing. We also reject TranServ’s request for rehearing for 

having been filed late, in violation of section 313(a) of the Federal Power Act (FPA). See 

16 USC 8351(a). The Commission does consider, however, these petitioners’ requests 

for clarification, to the extent they are not in fact requests for rehearing. We also address 

the merits of each request for rehearing to demonstrate that, had they been considered, 

our decision would be unchanged. 

4

 A list of parties filing comments in response to the July 30, 3007 technical 

conference is provided in Appendix B. 
Docket No. RM05-17-001, et al. - 5 -

II. Need for and Applicability of Order No. 888

A. The Need for Reform

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

transmission monopolists to deny transmission to competitors or to offer transmission on 

a basis that is inferior to that which they provide themselves.5

 The Commission sought to 

remedy that potential for discrimination through adoption of the pro forma OATT in 

Order No. 888. Despite the many accomplishments of Order No. 888, the Commission 

determined in Order No. 890 that the existing pro forma OATT continued to allow 

transmission providers substantial discretion in implementing some of its basic 

requirements. This discretion, in turn, created substantial opportunities for undue 

discrimination. Order No. 890 reformed the pro forma OATT to limit opportunities for 

undue discrimination and promote efficient use of the grid. 

8. In Order No. 890, the Commission rejected arguments that it was relying on 

unsubstantiated allegations of discriminatory conduct to justify its reforms. Although 

certain commenters did allege discriminatory conduct in response to the Notice of 

Proposed Rulemaking (NOPR) initiating this proceeding,6

 the Commission made clear 

that it was not making specific factual findings of discrimination and that such specific 

findings were not required in order for it to promulgate a generic rule to eliminate undue 

 5

 Order No. 888 at 31,682. 

6

 Preventing Undue Discrimination and Preference in Transmission Service, 

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

¶ 32,603 (2006) (NOPR). 
Docket No. RM05-17-001, et al. - 6 -

discrimination.7

 The Commission explained that it had ample grounds to act as necessary 

to limit opportunities for undue discrimination that continue to exist under the pro forma

OATT. 

Requests for Rehearing and Clarification

9. Many petitioners agree with the Commission on rehearing that reforms to the pro 

forma OATT are needed because there continues to be both the opportunity and incentive 

for transmission providers to engage in undue discrimination.8

 Two petitioners, however, 

seek rehearing of that finding as sufficient justification for adopting the reforms set forth 

in Order No. 890. 

10. E.ON U.S. argues that the Commission has not presented any actual evidence of 

discrimination or opportunities for undue discrimination. Without actual evidence of 

discrimination, E.ON U.S. argues that the Commission lacks reasoned support for its 

finding that the reforms adopted in Order No. 890 are necessary to remedy undue 

discrimination. E.ON U.S. states a particular concern for the cost of implementing these 

reforms. E.ON U.S. contends that, absent evidence of unduly discriminatory behavior, 

the burdensome nature of compliance with Order No. 890 outweighs the benefits of its 

reforms. 

 7

 See Order No. 890 at P 41 (citing Transmission Access Policy Study Group v. 

FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom., New York v. FERC, 535 U.S. 1 

(2002); National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C. Cir. 2006)). 

8

 See, e.g., Constellation, MISO, NRECA, Powerex, PSEG, and TAPS. 
Docket No. RM05-17-001, et al. - 7 -

11. Southern expresses similar concern that Order No. 890 lacks actual findings of 

discrimination. Southern claims that the theoretical claims of discrimination relied upon 

by the Commission are attenuated and inconsistent with statements discouraging 

commenters from making sweeping generalizations regarding undue discrimination. 

Rather than predicating Order No. 890 on the Commission’s authority to prevent undue 

discrimination, Southern suggests that the Commission clarify that it is promulgating 

these reforms pursuant to its authority to ensure just and reasonable rates and not to 

prevent undue discrimination. 

12. Southern also argues that the Commission failed to acknowledge other legal 

requirements and processes adopted after issuance of Order No. 888 that mitigate a 

transmission provider’s incentives to discriminate, such as the Standards of Conduct, 

enforcement audits, new civil penalty authority, and mandatory reliability standards. 

Southern contends that transmission providers have a pecuniary incentive to grant, rather 

than deny, customer requests since doing so provides additional OATT revenues. 

Southern argues that the Commission appears to equate discretion with opportunities for 

discrimination, yet in certain circumstances expressly acknowledges that the transmission 

provider retains discretion in certain activities. 

Commission Determination

13. The Commission concluded in Order No. 890 that reforms to the pro forma OATT 

were necessary to address remaining opportunities for undue discrimination by 

transmission providers. Despite the efforts of Order No. 888 and our subsequent reforms, 

including those cited by Southern, opportunities for undue discrimination continued to 
Docket No. RM05-17-001, et al. - 8 -

exist. Under section 206 of the FPA, the Commission has a continuing obligation to 

“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 no meet this standard.”9

 The Commission’s finding 

that continuing opportunities to discriminate exist therefore supports our action under 

FPA section 206 to adopt changes to the pro forma OATT. Upon review of the extensive 

record of this proceeding, including the support of a vast majority of commenters, the 

Commission remains convinced that the particular reforms adopted in Order No. 890 are 

appropriate to satisfy our obligation to remedy undue discrimination. 

14. We reject E.ON U.S.’ arguments that, without actual evidence of undue 

discrimination, Order No. 890 lacks reasoned support. As the Commission explained in 

Order No. 890, the courts have made clear that the Commission need not make specific 

factual findings of discrimination in order to promulgate a generic rule to eliminate undue 

discrimination. In Associated Gas Distributors v. FERC, the D.C. Circuit Court 

explained that the promulgation of generic rate criteria involves the determination of 

policy goals and the selection of the means to achieve them. 10 The court concluded that, 

just as courts do not insist on empirical data for every proposition upon which the 

selection depends, “[a]gencies do not need to conduct experiments in order to rely on the 

 9

 Order No. 888 at 31,669. 

10 824 F.2d 981 (D.C. Cir. 1987). 
Docket No. RM05-17-001, et al. - 9 -

prediction that an unsupported stone will fall.”11 The Commission exercised this 

authority in Order No. 890, discussing with particularity the concerns motivating each of 

the reforms adopted. As it did in Order No. 888, the Commission properly acted to limit 

continuing opportunities for undue discrimination, not to remedy actual instances of 

undue discrimination. 

15. We acknowledge, as argued by Southern, that it is appropriate for transmission 

providers to retain discretion in some areas and that such discretion does not necessarily 

equate to discrimination. It is also true that some OATT revenues may increase as 

requests for service are granted (such as for point-to-point requests), rather than denied. 

This is not always or even predominantly the case, however, given that rates for network 

service are based on load-ratio shares and revenues do not increase with designations of 

network resources unless new facilities are constructed. Moreover, there are competing 

incentives for a transmission provider to deny or restrict service to customers in certain 

circumstances and allowing broad discretion in such areas is no longer appropriate. The 

Commission identified these areas in Order No. 890, including the calculation of ATC, 

planning for transmission needs, and the provision of certain transmission services, and 

acted to remedy potential discrimination in each area. Notwithstanding the other legal 

requirements and processes cited by Southern, the Commission concluded in Order No. 

890 that the reforms adopted were necessary based on a decade of experience 

administering the pro forma OATT. While the Standards of Conduct, audit procedures, 

 11 Id. at 1008. 
Docket No. RM05-17-001, et al. - 10 -

and enhanced authority under the Energy Policy Act of 2005 (EPAct 2005)12 have aided 

the Commission in fulfilling its obligations under the FPA, the reforms adopted in Order 

No. 890 are also necessary to reduce opportunities for the exercise of undue 

discrimination, make undue discrimination easier to detect, and facilitate the 

Commission’s enforcement of the open access requirements. 

16. We appreciate that a significant amount of resources must be dedicated to 

implementation of the reforms adopted in Order No. 890 by transmission providers. We 

believe the burden of implementing these reforms is fully justified by the need to 

eliminate remaining opportunities for undue discrimination in the administration and 

implementation of open access requirements under the pro forma OATT. We note, 

moreover, that these reforms will benefit transmission providers seeking to comply with 

our regulations in good faith by providing more clarity regarding the requirements of the 

pro forma OATT previously left open to interpretation, thereby decreasing the possibility 

of disputes with transmission customers and enforcement actions by the Commission. 

The ability of transmission customers to misuse the tariffs to their own advantage, 

particularly in the scheduling process, has similarly been addressed. Taken together, we 

conclude that the benefits of our reforms outweigh the associated costs of 

implementation. 

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

U.S.C.). 
Docket No. RM05-17-001, et al. - 11 -

B. Core Elements of Order No. 888 that are Retained

17. Although Order No. 890 introduced many important reforms, the Commission also 

retained many core elements from Order No. 888. As noted in the NOPR, many 

provisions of Order No. 888 enjoy broad support from many sectors of the industry and 

the Commission did not intend in this proceeding to pursue the same level of industry 

restructuring undertaken there. Rather, the Commission intended Order No. 890 to 

strengthen the pro forma OATT while retaining the fundamental structure articulated in 

Order No. 888. 

18. The Commission thus retained the existing boundaries between wholesale and 

retail service drawn in Order No. 888. The Commission also retained the native load 

priority established in Order No. 888. The Commission stated that this priority continues 

to strike the appropriate balance between the transmission provider’s need to meet its 

native load obligations and the needs of other entities to obtain service from the 

transmission provider to meet their own obligations. Order No. 890 also did not alter the 

types of services required under Order No. 888, i.e., network service and point-to-point 

service. Finally, the Commission retained the functional unbundling requirement 

promulgated in Order No. 888. 

Requests for Rehearing and Clarification

19. South Carolina E&G objects to the Commission’s decision to retain the native 

load priority established in Order No. 888, arguing that FPA section 217 requires further 

protection for native load service. South Carolina E&G states that the native load priority 

adopted under Order No. 888 was implemented so that all customers, native load and 
Docket No. RM05-17-001, et al. - 12 -

non-native load, would be entitled to equivalent, nondiscriminatory service.13 South 

Carolina E&G argues that FPA section 217(k) now entitles load-serving entities (LSEs) 

to use their transmission systems to meet their state-law imposed native load service 

obligations and that this entitlement can no longer be deemed discriminatory under the 

FPA. To the extent an OATT provision compromising native load service is grounded in 

a finding of undue discrimination, South Carolina E&G argues that it must yield to the 

need to meet native load service obligations. 

20. Joined by South Carolina Regulatory Staff, South Carolina E&G objects in 

particular to the Commission’s decision to retain equal curtailment priority for all firm 

service.14 These petitioners argue that requiring transmission providers to curtail service 

to network and point-to-point customers on a basis comparable to the curtailment of 

service to native load customers unfairly exalts non-native customers at the expense of 

the native load that financed the transmission system. They also contend the 

Commission’s decision is inconsistent with Northern States Power Co. v. FERC,

15 which 

they argue prohibits mandating comparable curtailment priority among native load and 

non-native load services in the face of a state commission edict requiring a transmission 

 13 Citing Louisville Gas & Elec. Co., 114 FERC ¶ 61,282 at P 125 (2006). 

14 South Carolina E&G and South Carolina Regulatory Staff also argue that 

reforms related to planning redispatch and conditional firm, rollover rights, and capacity 

reassignment are in violation of FPA section 217. We address those arguments in 

sections III.D.1, III.D.2, and III.C.3 respectively. 

15 176 F.3d 1090 (8th Cir. 1999). 
Docket No. RM05-17-001, et al. - 13 -

provider to give its native load top curtailment priority. In their view, this precedent must 

be read broadly in light of enactment of FPA section 217(k), which they contend 

peremptorily counters any argument that priority for native load would be discriminatory. 

21. E.ON LSE similarly argues that FPA section 217 categorically protects an LSE’s 

use of firm transmission service to the extent that such transmission service is required to 

meet the LSE’s service obligation. E.ON LSE asks the Commission to allow LSEs to 

deviate from the requirements of Order No. 890 in circumstances where, in the LSE’s 

good faith judgment, compliance would adversely affect the provision of firm 

transmission service to native load protected by FPA section 217. 

22. TDU Systems request clarification or rehearing to confirm that there is no 

preference under the reformed pro forma OATT for a public utility transmission 

provider’s native load over the service obligations of other LSEs that use their 

transmission system. TDU Systems argue that section 217(a) of the FPA does not 

distinguish between the service obligations of transmission providers and the service 

obligations of their load serving customers and, therefore, neither should the pro forma

OATT. 

Commission Determination 

23. The Commission affirms the decision to retain the native load protections 

embodied in Order No. 888, as enhanced by the reforms adopted in Order No. 890. In 

Order No. 888, the Commission gave public utilities the right to reserve existing 

transmission capacity needed for native load growth reasonably forecasted within the 
Docket No. RM05-17-001, et al. - 14 -

utility’s current planning horizon.16 The Commission also allowed transmission 

providers to restrict rollover rights based on reasonably forecasted need at the time the 

contract is executed.17 Contrary to petitioner’s assertions, the native load protections 

affirmed in Order No. 890 satisfy the requirements of FPA section 217. Section 217 

applies not only to distribution utilities providing service to end-users, but also to electric 

utilities with long-term contracts to provide service to a distribution utility.18 Congress 

placed each of these types of customers on equal footing, regardless of their status as a 

network or firm point-to-point customer under the pro forma OATT or a transmission 

provider serving its native load. We therefore disagree with petitioners that section 217 

requires the Commission to give top curtailment priority solely to network customers or 

the transmission provider serving native load. 

24. We decline to allow LSEs to deviate from the requirements of the pro forma

OATT as they believe necessary to serve their native load, as suggested by E.ON LSE. 

Section 217 is intended to facilitate the ability of all utilities using firm transmission to 

 16 See Order No. 888 at 31,394. 

17 See id. at 31,745. 

18 See EPAct 2005 sec. 1233(a)(3) (to be codified at section 217(a)(3) of the FPA, 

16 USC 824q(a)(3)). Petitioners’ reliance on Northern States Power Co. v. FERC, 

176 F.3d 1090 (8th Cir. 1999), is therefore misplaced. As the Commission has explained, 

the court upheld our authority to require pro rata curtailment of both network/native load 

and firm point-to-point service except in the limited circumstance when it would require 

the shedding of bundled retail load. Indeed, FPA section 217 could be read to grant 

electric utilities with long-term contracts to provide service to a distribution utility equal 

curtailment priority with other LSEs even in that limited situation, although we decline to 

address that argument here as it has not been raised on rehearing. 
Docket No. RM05-17-001, et al. - 15 -

meet their long-term service obligations, which the statute defines broadly to include not 

only service to end-users, but also distribution utilities serving end-users.19 The 

requirements of the pro forma OATT and the reforms adopted in Order No. 890 

appropriately balance the needs of these various classes of transmission customers, 

including the transmission provider’s native load, LSE customers serving network load, 

and other firm users of the system. This is entirely consistent with, if not expressly 

required by, FPA section 217. 

C. Scope and Applicability of Order No. 890

25. The reforms adopted in Order No. 890 apply to all transmission providers, 

including Commission-approved regional transmission organizations (RTOs) and 

independent system operators (ISOs), and non-public utility transmission providers with 

reciprocity obligations. The particular process for implementing certain of the reforms 

adopted in Order No. 890 varied depending on the type of transmission provider at issue. 

26. For those transmission providers that have not been approved as ISOs or RTOs, 

and whose facilities are not under the control or within the footprint of an ISO or RTO, 

Order No. 890 established a two-tiered compliance process for adopting the non-rate 

terms and conditions of the revised pro forma OATT. These transmission providers were 

directed to submit FPA section 206 compliance filings that contain the revised non-rate 

terms and conditions of the revised pro forma OATT within 60 days after publication of 

 19 See EPAct 2005 sec 1233(a) (to be codified at section 217(a) of the FPA, 16 

USC 824q(a)). 
Docket No. RM05-17-001, et al. - 16 -

the order in the Federal Register.20 Any of these transmission providers that wished to 

retain a previously-approved variation from the Order No. 888 pro forma OATT that was 

substantively affected by a reform adopted in Order No. 890 were directed to submit, 

within 30 days after publication of Order No. 890 in the Federal Register, a request under 

FPA section 205 to retain those previously-approved variations, provided they continued 

to be consistent with or superior to the revised pro forma OATT adopted in Order No. 

890. 

27. ISO and RTO transmission providers were directed to submit FPA section 206 

compliance filings, within 210 days after the publication of Order No. 890 in the Federal 

Register, that contain the non-rate terms and conditions set forth in Order No. 890 or that 

demonstrate that their existing tariff provisions are consistent with or superior to the 

revised provisions of the pro forma OATT. Transmission-owning members of ISOs and 

RTOs, and non-ISO/RTO transmission providers within the footprint of an ISO or RTO, 

were similarly directed to make any necessary tariff filings within 210 days of its 

publication in the Federal Register. 

28. With regard to non-public utility transmission providers, the Commission retained 

the reciprocity language of the Order No. 888 pro forma OATT with a few modifications. 

First, the Commission updated the language to contain references to ISOs and RTOs, 

 20 The Commission subsequently extended by 60 days the date on which the 

reforms adopted in Order No. 890 would have otherwise been effective. See Preventing 

Undue Discrimination and Preference in Transmission Service, 119 FERC ¶ 61,037 

(2007) (April 11 Order). 
Docket No. RM05-17-001, et al. - 17 -

requiring transmission customers that are members of, or that take service from, an 

ISO/RTO to make comparable service available to other members of the ISO/RTO. As 

proposed in the NOPR, the Commission did not adopt a generic rule to implement FPA 

section 211A, which allows the Commission to require an unregulated transmitting utility 

to provide transmission services at rates that are comparable to those it charges itself and 

under non-rate terms and conditions that are comparable to those it applies to itself, and 

are not unduly discriminatory or preferential. The Commission instead explained that it 

would follow a case-by-case approach to implementing FPA section 211A. 

Requests for Rehearing and Clarification

29. Few petitioners question the applicability of Order No. 890, although some are 

concerned with the timing of the compliance actions required by the Commission. 

Southern asks the Commission to grant rehearing and extend the initial compliance 

deadlines by 60 days and to remain open to further requests for extension if the deadlines 

set forth in Order No. 890 cannot be met. MidAmerican asks the Commission to extend 

the effective date for the revisions to the pro forma OATT to the first day of the month 

following the effective date of these reforms. MidAmerican contends that it will be 

burdensome for transmission providers and confusing to transmission customers to 

implement the reforms adopted in Order No. 890 in the middle of a billing cycle. 

30. TDU Systems express concern with the burden of reviewing section 205 filings by 

transmission providers seeking a determination from the Commission that a previouslyapproved variation from Order No. 888 continues to be consistent with or superior to the 

revised pro forma OATT. TDU Systems contend that reviewing and evaluating these 
Docket No. RM05-17-001, et al. - 18 -

filings will be a large and time-consuming process. TDU Systems ask the Commission to 

allow transmission customers 45 days to perform their own evaluation and comment 

upon these filings, while retaining a 90-day deadline for the Commission to process the 

filings. Alternatively, TDU Systems request rehearing of the Commission’s decision not 

to stagger the due dates for the various compliance filings required in Order No. 890. 

31. Although they recognize that Order No. 890 preserves existing waivers of the 

obligations to file an OATT, Unitil and Alcoa seek explicit confirmation that their 

waivers of the obligation to maintain an Open Access Same-Time Information System 

(OASIS) site are still valid. Unitil notes that the Commission has found that it does not 

operate or control an interstate transmission grid.21 In addition, Unitil states that it 

voluntarily offers relevant information to ISO-NE for posting on its OASIS website. 

Similarly, Alcoa notes that the Commission has granted waiver of OASIS requirements 

to its Long Sault division, which owns five transmission lines in northern New York 

connecting Alcoa to its electric energy suppliers.22 Thus, Unitil and Alcoa seek 

confirmation that the Commission did not intend the OASIS requirements outlined in 

Order No. 890 to apply to their operations. 

32. NRECA requests clarification, or in the alternative rehearing, that the Commission 

did not intend in Order No. 890 to extend reciprocity obligations beyond transmission 

 21 Citing Northern States Power Co., 76 FERC ¶ 61,250 at 62,297 (2002). 

22 Citing Alcoa Power Generating, Inc. (Long Sault Division), 116 FERC ¶ 61,257 

(2006). 
Docket No. RM05-17-001, et al. - 19 -

owning members of an ISO or RTO. NRECA contends that the Commission’s 

modification to the pro forma OATT creates ambiguity by imposing the reciprocity 

obligation for all “members” of an ISO or RTO. NRECA points out that some members 

of ISOs and RTOs do not own transmission, such as transmission dependent utilities, 

state regulatory authorities and eligible end-use customers. NRECA argues that 

expanding the reciprocity obligation to require non-public utility transmission providers 

to provide service to non-transmission owning members of an ISO or RTO would 

contradict Commission precedent23 and be unsupported by the record in this proceeding. 

33. WSPP requests that the Commission establish a date by which it must submit a 

compliance filing containing the non-rate terms and conditions of the revised pro forma

OATT. WSPP states that it is neither a transmission provider nor an RTO/ISO and, 

instead, only has a limited open access transmission tariff on file with the Commission. 

WSPP states that this tariff only applies to its transmission-owning members that do not 

otherwise have an OATT. 

Commission Determination

34. In the April 11 Order, the Commission granted requests by EEI and others to 

extend by 60 days the date by which transmissions providers outside of ISO/RTO regions 

would have to submit compliance filings containing the non-rate terms and conditions of 

the revised pro forma OATT.24 Southern’s request for rehearing on this point is therefore 

 23 Citing American Transmission Co. LLC, 95 FERC ¶ 61,387 (2001). 

24 April 11 Order at P 20. 
Docket No. RM05-17-001, et al. - 20 -

moot. Similarly, we reject as unnecessary TDU Systems’ request to allow transmission 

customers additional time to evaluate and comment upon compliance filings. These 

filings have already been made, comments have been filed, and in many cases orders 

addressing the filings have been issued. 

35. The Commission also determined in the April 11 Order that it would be reasonable 

for a transmission provider to request that the imbalance-related provisions in Schedule 4 

and Schedule 9 of the pro forma OATT be made effective on the first day of the billing 

cycle following the effectiveness of the underlying imbalance-related reforms.25 

MidAmerican does not explain or otherwise justify the need to delay the effectiveness of 

any other reforms until the following billing cycle. We therefore reject as moot 

MidAmerican’s request to extend the effective date of the imbalance-related reforms 

adopted in Order No. 890 until the following billing cycle and reject as unsupported its 

request to extend the effective date of all other reforms adopted in Order No. 890. 

36. The Commission made clear in Order No. 890 that the reforms therein were not 

intended to disturb any existing waivers of the obligation to file an OATT or otherwise 

offer open access transmission service.26 The criteria for waiver of Order No. 890, 

moreover, remains unchanged from that used to evaluate the requests for waiver under 

Order Nos. 888 and 889. Revocation of any waivers will continued to be considered on a 

case-by-case basis in response to concerns raised by interested parties. We clarify that 

 25 Id. at P 22. 

26 See Order No. 890 at P 135, n.105. 
Docket No. RM05-17-001, et al. - 21 -

this applies equally to existing waivers of Order No. 889 and requirements to maintain an 

OASIS site. 

37. We grant rehearing, in response to NRECA, to revise section 6 of the pro forma

OATT to require a customer that is a member of or that takes service from an RTO or 

ISO to provide comparable service, to the extent it owns transmission facilities, only to 

the transmission-owning members of the RTO or ISO. The Commission has expressed 

concern in the past that failure to grant reciprocity to transmission-owning members of an 

RTO or ISO would cause those members to lose the right to reciprocity solely as a result 

of participating in the RTO or ISO.27 We did not intend to expand that obligation in 

Order No. 890 to other members of an RTO or ISO when revising the language of section 

6 of the pro forma OATT to refer to RTOs and ISOs. 

38. Below the Commission adopts various other revisions to the pro forma OATT in 

response to requests for rehearing and clarification. These revisions do not disturb the 

fundamental nature of the reforms adopted in Order No. 890 and, thus, we do not 

anticipate any difficulty in their implementation or disruption in on-going compliance 

efforts. We direct transmission providers that have not been approved as RTOs or ISOs, 

and whose facilities are not in the footprint of an RTO or ISO, to submit an FPA section 

206 filing that contains the revised non-rate terms and conditions of the pro forma OATT 

stated in Appendix C within 60 days of publication of this order in the Federal Register. 

 27 See American Transmission Company LLC, 93 FERC ¶ 61,267 at 61,858-59 

(2000), reh’g denied, 95 FERC ¶ 61,387 at 62,446 (2001). 
Docket No. RM05-17-001, et al. - 22 -

We direct RTO and ISO transmission providers, transmission providers whose facilities 

are in the footprint of an RTO or ISO, and WSPP to submit an FPA section 206 filing 

that contains the revised non-rate terms and conditions of the pro forma OATT as stated 

within Appendix C within 90 days of publication of this order in the Federal Register. 

III. Reforms of the OATT 

A. Consistency and Transparency of ATC Calculations 

39. In Order No. 890, the Commission concluded that the lack of consistency and 

transparency in the methodology for calculating ATC creates the potential for undue 

discrimination in the provision of open access transmission service. To remedy this lack 

of consistency and transparency, the Commission directed public utilities, working 

through the NERC reliability standards and NAESB business practices development 

processes, to produce workable solutions to implement the ATC-related reforms adopted 

by the Commission. A number of petitioners seek rehearing and/or clarification 

regarding the Commission’s ATC-related rulings, which we address below. 

1. Consistency

a. Necessary Degree of Consistency

40. The Commission required industry-wide consistency of all ATC components28 and 

certain definitions, data inputs, data exchange, and modeling assumptions in order to 

reduce the potential for undue discrimination in the provision of transmission service. 

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

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

(TRM). 
Docket No. RM05-17-001, et al. - 23 -

Although the Commission concluded that the number of industry-wide ATC calculation 

formulas should be few in number, it did not require that a single ATC calculation 

methodology be applied by all transmission providers. The Commission found that it is 

not the methodologies for calculating ATC that create the opportunity for undue 

discrimination, rather the variability in the calculation of the components of ATC and the 

lack of a detailed description of the ATC calculation methodology and underlying 

assumptions used by the transmission provider. 

41. The Commission noted that NERC was then in the process of developing 

standards for three ATC calculation methodologies: contract or rated path ATC, network 

ATC, and network Available Flowgate Capacity (AFC). The Commission concluded 

that, if all of the ATC components and certain data inputs and assumptions are consistent, 

the use of the three ATC calculation methodologies included in reliability standards being 

developed would be acceptable. With regard to network AFC, the Commission 

specifically directed public utilities, working through NERC, to develop an AFC 

definition and requirements used to identify a particular set of transmission facilities as a 

flowgate. However, the Commission reminded transmission providers that our 

regulations require the posting of ATC values associated with a particular path, not AFC 

values associated with a flowgate. The Commission therefore directed public utilities, 

working through NERC, to develop in the MOD-001 standard a rule to convert AFC into 

ATC values to be posted by transmission providers that currently use the flowgate 

methodology. 
Docket No. RM05-17-001, et al. - 24 -

42. The Commission also required further clarification regarding the calculation 

algorithms for firm and non-firm ATC. The Commission directed public utilities, 

working through NERC, to modify related ATC standards by implementing the following 

principles: (1) for firm ATC calculations, the transmission provider shall account only 

for firm commitments; and (2) for non-firm ATC calculations, the transmission provider 

shall account for both firm and non-firm commitments, postbacks of redirected services, 

unscheduled service, and counterflows. 

Requests for Rehearing and Clarification 

43. Southern requests that the Commission clarify that consistency in ATC 

methodologies and CBM and TRM calculations must not take precedence over reliability 

and that some transmission provider discretion is necessary. Southern states that, in 

several places, Order No. 890 discusses minimizing transmission provider discretion in 

order to achieve consistency.29 Southern contends that totally eliminating this discretion 

would not allow transmission providers to address unique system conditions in ATC, 

CBM, and TRM calculations, which would impact system reliability. Southern claims 

that eliminating transmission provider discretion also would lead to more conservative 

modeling, which would likely result in understated amounts of ATC and an inefficient 

use of the system.30 To the extent making the treatment of certain ATC parameters or 

 29 Citing Order No. 890 at P 207. 

30 Southern suggests that one example of when a transmission provider should 

have discretion is when modeling long-term firm transmission service reservation from a 

combustion turbine generating facility. Southern argues that, by its nature, such a 

 (continued...) 
Docket No. RM05-17-001, et al. - 25 -

CBM or TRM calculations consistent would affect reliability, Southern asks that 

transparency in the treatment of those parameters and calculations be required, but that 

strict consistency not be enforced. 

44. MidAmerican requests clarification that AFC quantities do not need to be 

converted into control area-to-control area path ATC quantities and that the Commission 

is not eliminating the coordination of individual transmission provider service with seams 

agreements and/or regional tariff service on flowgates. MidAmerican asks the 

Commission to confirm that it is merely intending to require NERC to define a flowgate 

ATC quantity which is equal to or related to the flowgate AFC. MidAmerican contends 

that transmission customers, operators, and owners will not benefit from the conversion 

of flowgate AFCs into control area-to-control area path ATCs, the elimination of AFC as 

a useful transmission commodity, or the elimination of the coordination of individual 

provider and regional transmission service over flowgates. To the extent the Commission 

feels there is a comparability benefit for the conversion of AFC to ATC, MidAmerican 

requests clarification that providing transmission customers with a mechanism on OASIS 

to query/assess the effective ATC on a specific transmission path over a specific time is 

sufficient for compliance with the transmission provider’s ATC posting obligation. 

 

generating facility normally will not often run in off-peak times. During those times, or 

when there is an impending outage of a generating facility, Southern argues that the 

transmission provider should have the discretion to reflect the operating characteristics of 

the generating facility by not including transmission service from the facility in its model. 
Docket No. RM05-17-001, et al. - 26 -

45. E.ON U.S. requests clarification of the requirement that AFC calculations be 

converted into ATC for purposes of posting. E.ON U.S. states that some RTOs, such as 

MISO and others, utilize AFC and do not calculate or post ATC for their systems. Due to 

interactions with these RTOs, E.ON U.S. now calculates AFC as well. E.ON requests 

that the Commission clarify that if RTOs and their member utilities are granted waivers 

of the requirement to calculate and post ATC, in favor of AFC, all transmission owning 

utilities in the region should be able to request a waiver on the same basis. E.ON claims 

that allowing all transmission-owning utilities within a region to calculate AFC (instead 

of ATC) will result in greater accuracy and consistency within the industry. 

46. Although it does not challenge the Commission’s decision not to require a single, 

industry-wide ATC calculation method, TDU Systems claims that the Commission fails 

to address the situation where transmission providers on a single interface choose 

different ATC calculation methods. TDU Systems argue that transmission providers 

must be required to provide consistent ATC values on either side of an interface. TDU 

Systems therefore request that adjacent transmission providers be required to coordinate 

to provide consistent ATC values across their common interfaces. 

47. NorthWestern requests that the Commission clarify that the consistency 

requirements of Order No. 890 do not prohibit utilities from reducing transfer capability 

for the purchase of reliability services. According to NorthWestern, some transmission 

providers may have to acquire various generation-based services, such as load following 

and regulation service, in the marketplace in order to meet reliability criteria. 

NorthWestern argues that some means should be allowed for retaining transmission at no 
Docket No. RM05-17-001, et al. - 27 -

cost for such deliveries, even though they do not meet the strict definition of CBM, since 

they are made for reliability reasons and no single user of the system would otherwise 

reimburse the transmission provider for the associated costs. 

48. EPSA and Williams request clarification that ATC and AFC calculations should 

be determined and posted in real-time, not just as planning information, and that the 

transmission provider be required to post results of its system utilization for ETC. 

Williams contends that this would augment the transparency deemed critical to a coherent 

and uniform calculation of ATC by enabling interested stakeholders and the Commission 

to verify the ATC calculations performed by transmission providers. 

Commission Determination

49. The Commission affirms the decision in Order No. 890 to require consistency of 

all ATC components and certain definitions, data inputs, data exchange and modeling 

assumptions. We continue to believe such consistency is necessary to reduce the 

potential for undue discrimination in the provision of transmission service. 

50. We disagree with Southern that increasing consistency with respect to the 

determination of ATC is contrary to reliability. Use of the NERC reliability standards 

process will, as a matter of course, guard against any unintended reduction in reliability. 

Nevertheless, we agree that reliability standards cannot address every unique system 

difference or differences in risk assumptions when modeling expected flows, which 

necessitates leaving room for limited discretion on the part of the transmission provider. 

We believe that the ATC requirements in Order No. 890 allow sufficient flexibility so 

that utilities, working through NERC/NAESB, can develop ATC standards that continue 
Docket No. RM05-17-001, et al. - 28 -

to provide reliability and are compatible with all other mandatory reliability standards or 

business practices, yet provide discretion where appropriate. If a transmission provider is 

faced with unique system conditions or modeling assumptions related to firm 

transmission service reservations31 that are not addressed in the ATC-related NERC 

reliability standards, it must make them transparent through its Attachment C filing and 

the OASIS posting requirements regarding ATC calculation and modeling approach, 

studies, models and assumptions and implement them consistently for all transmission 

customers. 

51. We deny MidAmerican’s request for clarification that AFC values do not need to 

be converted into ATC postings of control area-to-control area path quantities. As the 

Commission explained in Order No. 890, our regulations require the posting of ATC 

values associated with a particular path, not AFC values associated with a flowgate.32 

The Commission did not amend that requirement in Order No. 890 and MidAmerican 

fails to justify doing so now. To the extent MidAmerican or its customers find it 

beneficial also to post AFC, MidAmerican is free to post both ATC and AFC values. In 

response to E.ON U.S., however, we clarify that transmission-owning utilities in an RTO 

 31 Transmission providers use different assumptions related to the percentage of 

firm reservations that are actually scheduled and flow. 

32 See Order No. 890 at P 211. ATC values must be posted for control area to 

control area interconnections, paths for which service is denied, curtailed or interrupted 

for more than 24 hours in the past 12 months, and paths for which a customer requests to 

have ATC or TTC posted. See 18 CFR 37.6(b)(1)(i). 
Docket No. RM05-17-001, et al. - 29 -

region can request waiver of the requirement to convert AFC calculations into ATC for 

posting purposes in the event the RTO has been granted such a waiver. 

52. In response to TDU Systems, we clarify that adjacent transmission providers must 

coordinate and exchange data and assumptions to achieve consistent ATC values on 

either side of a single interface. This is applicable to any neighboring transmission 

providers no matter whether they use the same or different ATC methodologies. We 

note, however, that the anticipated consistency is for available capability in the same 

direction across an interface. 

53. We clarify in response to NorthWestern that TRM may be used to accommodate 

the procurement of ancillary services used to provide service under the pro forma OATT. 

We deny as premature EPSA’s and Williams’ requests for clarification regarding the realtime determination and posting of ATC and AFC values, as well as posting of utilization 

of transmission provider’s own system ETC. In Order No. 890, the Commission required 

an exchange of the data both for short and long-term ATC/AFC calculation that will 

increase the accuracy of ATC calculations.33 The Commission also required that ATC be 

recalculated by all transmission providers on a consistent time interval, and in a manner 

that closely reflects the actual topology of the system, load forecast, interchange 

schedules, transmission reservations, facility ratings, and other necessary data, and that 

NERC/NAESB revise the related reliability standard and business practices 

 33 See Order No. 890 at P 310. 
Docket No. RM05-17-001, et al. - 30 -

accordingly.34 EPSA and William should address their concerns through the NERC and 

NAESB processes implementing these requirements. 

b. Process to Achieve Consistency

54. The Commission directed public utilities, working through NERC and NAESB, to 

modify the ATC-related reliability standards and business practices in accordance with 

specific direction provided in Order No. 890. The Commission concluded that the NERC 

reliability standards development process and the NAESB business standards 

development process are the appropriate forums for developing consistency in ATC 

calculations. To that end, public utilities were directed, working through NERC, to 

modify the ATC-related reliability standards within 270 days after the publication of 

Order No. 890 in the Federal Register, i.e., December 10, 2007. Public utilities were also 

directed, working through NAESB, to develop business practices that complement 

NERC’s new reliability standards within 360 days after the publication of Order No. 890 

in the Federal Register, i.e., March 10, 2008. 35 

Requests for Rehearing and Clarification

55. Several petitioners contend that the Commission’s direction to public utilities, 

working through NERC, to modify standards to meet specific ATC requirements is 

 34 See id. at P 301. 

35 The Commission has since extended these compliance deadlines to May 9, 

2008, and August 7, 2008, respectively. See Preventing Undue Discrimination and 

Preference in Transmission Service, Notice of Extension of Time, Docket Nos. RM05-

17-000, et al. (Dec. 6, 2007). 
Docket No. RM05-17-001, et al. - 31 -

tantamount to dictating reliability standards in violation of FPA section 215.36 These 

petitioners assert that system reliability will be best maintained if NERC, having been 

certified by the Commission as the ERO, is afforded discretion in creating the necessary 

reliability standards in the first instance prior to submission to the Commission for 

approval consistent with section 215.37 EEI and Southern suggest that the Commission 

give guidance and direction to NERC on how standards should be developed, but not be 

overly prescriptive. E.ON LSE argues that the Commission should require, or at least 

permit, NERC to consolidate its ATC development process with its ongoing reliability 

standards process to develop policies, but should refrain from rewriting any standards 

developed through that consolidated process. 

Commission Determination

56. The Commission affirms the decision in Order No. 890 to rely on the NERC 

reliability standards development process, and the NAESB business practices 

development process, to achieve a more coherent and uniform determination of ATC. 

We disagree that this conflicts with the Commission’s obligations under section 215 of 

the FPA. In Order No. 693, the Commission exercised its authority under FPA section 

215 to direct the ERO to modify the existing modeling, data, and analysis (MOD) 

standards related to ATC calculation, providing guidance consistent with our 

 36 E.g., EEI, E.ON LSE, and Southern. 

37 Citing 16 USC 824o(d)(2) (requiring the Commission to “give due weight to the 

technical expertise of the [ERO]” on reliability matters). 
Docket No. RM05-17-001, et al. - 32 -

requirements in Order No. 890. The Commission clarified that, where Order No. 693 

identified a concern and offered a specific approach to address the concern, the 

Commission would consider an equivalent alternative approach provided that the ERO 

demonstrated that the alternative would address the Commission’s underlying concern or 

goal as efficiently and effectively as the Commission’s proposal.38 We believe this 

provides the appropriate flexibility for NERC, while ensuring that the Commission act to 

remedy the potential for undue discrimination in the calculation of ATC. 

c. Applicability to ISOs, RTOs, and Non-Public Utility 

Transmission Providers

57. The Commission did not require ISO and RTO transmission providers to 

“rejustify” existing provisions in their OATTs that are not affected in a substantive 

manner by the revisions to the pro forma OATT in the Final Rule. However, the 

Commission did require all transmission providers, including an ISO or RTO, to 

demonstrate that variations from the tariff modifications required in Order No. 890 

continue to satisfy the consistent with or superior to standard. With respect to the 

application of the ATC requirements of Order No. 890, the Commission noted that ISOs 

and RTOs would be required to comply with reliability standards developed under FPA 

section 215. 

 38 See Mandatory Reliability Standards for the Bulk Power System, Order No. 

693, 72 FR 16,416 (Apr. 4, 2007), FERC Stats. & Regs. ¶ 31,242 (2007) (Order No. 

693), order on reh’g, 120 FERC ¶ 61,053 (2007) (Order No. 693-A). Pending completion 

of the NERC/NAESB standardization process, each transmission provider must perform 

its ATC-related calculations in accordance with the methodology set forth in Attachment 

C to its OATT, as revised to comply with Order No. 890. 
Docket No. RM05-17-001, et al. - 33 -

Requests for Rehearing and Clarification

58. Because Order No. 890 did not exempt ISOs/RTOs from the new ATC standards 

or curtailment information posting requirements, NYISO asks the Commission to clarify 

that NERC and NAESB must develop ATC standards and curtailment information 

posting rules that accommodate ISOs/RTOs. NYISO anticipates that ATC calculations 

will continue to be of limited significance within its control area, but acknowledges that it 

does calculate ATC at its external interfaces and also uses ATC to determine the 

availability of non-firm transmission service, i.e., service for customers that do not wish 

to be exposed to congestion charges. NYISO states that it, therefore, has an interest and 

intends to participate in the NERC and NAESB processes developing new ATC standards 

and curtailment information posting requirements. 

59. NYISO contends, however, that stakeholders from traditional systems will have a 

greater interest in the development of those rules and, as a result, that the NERC and 

NAESB processes may produce rules that primarily reflect the needs of traditional 

systems and do not accommodate ISOs/RTOs that are based upon locational marginal 

pricing of transmission. NYISO argues that Order No. 890 requires NERC and NAESB 

to develop standards that suit both traditional systems as well as the ISOs/RTOs that 

cover more than half of the load in the United States. NYISO requests that the 

Commission expressly state its expectation that the NERC and NAESB processes will 

produce standards that fulfill Order No. 890’s objectives of transparency and interregional consistency, yet that are sufficiently flexible to work for ISO/RTO regions. 
Docket No. RM05-17-001, et al. - 34 -

Commission Determination

60. Order No. 890 requires NERC and NAESB to develop a single set of ATC-related 

standards that will apply to all transmission providers, including RTOs and ISOs. We 

understand that the NERC ATC standard drafting team includes representatives from 

various industry sectors, including RTOs/ISOs, and we encourage NYISO to participate 

in the standard development process to provide NERC an opportunity to address its 

concerns. To the extent NYISO feels its concerns are not address in this process, it 

should bring the issue to the Commission’s attention on review of the resulting reliability 

standards. 

d. ATC Components

61. In Order No. 890, the Commission adopted certain requirements regarding the 

components of ATC (i.e., TTC/TFC, ETC, CBM and TRM) necessary to achieve 

consistency and, in turn, limit the potential for undue discrimination in the calculation of 

ATC. Petitioners request rehearing and clarification of the Commission’s determinations 

related to ETC, CBM and TRM, which we address in turn. 

 (1) ETC

62. The Commission adopted the NOPR proposal and directed public utilities, 

working through NERC and NAESB, to develop a consistent approach for determining 

the amount of transfer capability a transmission provider may set aside for its native load 

and other committed uses. The Commission determined that ETC should be defined to 

include committed uses of the transmission system, including (1) native load 

commitments (including network service), (2) grandfathered transmission rights, (3) 
Docket No. RM05-17-001, et al. - 35 -

appropriate point-to-point reservations,39 (4) rollover rights associated with long-term 

firm service, and (5) other uses identified through the NERC process. The Commission 

determined that ETC should not be used to set aside transfer capability for any type of 

planning or contingency reserve, which are to be addressed through CBM and TRM.40 In 

addition, for short-term ATC calculations, all reserved but unused transfer capability 

(non-scheduled) must be released as non-firm ATC. 

63. The Commission also found that inclusion of all requests for transmission service 

in ETC would likely overstate usage of the system and understate ATC. The 

Commission therefore found that reservations that have the same point of receipt (POR) 

(generator) but different point of delivery (POD) (load), for the same time frame, should 

not be modeled in the ETC calculation simultaneously if their combined reserved 

transmission capacity exceeds the generator’s nameplate capacity at the POR. The 

Commission directed public utilities, working through NERC, to develop requirements in 

MOD-001 that lay out clear instructions on how these reservations should be modeled. 

The Commission also concluded that some elements of ETC are candidates for business 

practices instead of reliability standards and directed public utilities, working through 

 39 The Commission explained that the reference to “appropriate point-to-point 

reservations” meant that reservations accounted for under ETC depend on the firmness 

and duration of the reservation. The Commission stated that the specific characteristics 

should be developed in the reliability standard. 

40 TRM also includes such things as loop flow and parallel path flow. 
Docket No. RM05-17-001, et al. - 36 -

NAESB, to develop business practices necessary for full implementation of the MOD001 reliability standard. 

Requests for Rehearing and Clarification

64. TDU Systems contend that, although the Commission defined the ETC component 

of ATC to include committed uses of the transmission system, it did not clearly identify 

how requests for transmission service are to be treated. TDU Systems question whether 

the Commission’s use of the term “committed requests” is the same as “confirmed 

requests” for service. In order to provide greater clarity, certainty and transparency to the 

ATC calculation process, TDU Systems ask the Commission to clarify that “committed 

requests” means the same thing as “confirmed requests,” as this term is generally 

understood throughout the industry. 

65. TranServ requests clarification that the Commission’s statement that all reserved 

but unused transfer capability (non-scheduled) shall be released as non-firm ATC was 

limited to the release of unscheduled firm transmission capability and not intended to 

require transmission providers to release unscheduled non-firm capability for additional 

non-firm sales.41

Commission Determination

66. The Commission clarifies in response to TDU Systems’ request that the reference 

to “committed requests” in Order No. 890 was intended to refer to confirmed 

transmission service requests. Once a service request has been approved by the 

 41 Citing Order No. 890 at P 244, 389. 
Docket No. RM05-17-001, et al. - 37 -

transmission provider and confirmed by the transmission customer, it should be taken 

into account when determining ETC. 

67. We also agree with TranServ that the Commission’s reference to releasing unused 

(non-scheduled) transfer capability as non-firm ATC applies to unscheduled firm 

transmission capability, since all unused non-firm capacity is deemed available to any 

entity meeting the scheduling requirements. This does not alter the requirement that the 

transmission provider offer all available capacity, firm or non-firm, as applicable, 

consistent with our long-standing open access principles. 

 (2) CBM

68. The Commission directed public utilities, working through NERC and NAESB, to 

develop clear standards and business practices for how the CBM value is determined, 

allocated across transmission paths and flowgates, and used. To ensure that CBM is used 

for its intended purpose, the Commission provided that CBM shall only be used to allow 

an LSE to meet its generation reliability criteria. The Commission rejected requests to 

allow CBM to be used to meet reserve-sharing needs, explaining that TRM is the 

appropriate category for that purpose. Public utilities were directed to work with NAESB 

to develop an OASIS mechanism that will allow for auditing of CBM usage. 

69. The Commission clarified that each LSE within a transmission provider’s control 

area has the right to request the transmission provider to set aside transfer capability as 

CBM for the LSE to meet its historical, state, RTO, or regional generation reliability 

criteria requirement such as reserve margin, loss of load probability, the loss of largest 

units, etc. It also determined that LSEs should be permitted to call for the use of CBM, 
Docket No. RM05-17-001, et al. - 38 -

pursuant to conditions established in the reliability standards development process. 

Public utilities were directed to work through NERC to modify the CBM-related 

standards to specify the generation deficiency conditions during which an LSE will be 

allowed to use the transfer capability reserved as CBM. The Commission also directed 

public utilities, working through NERC, to develop clear requirements for allocating 

CBM to paths and flowgates and concluded that transmission capacity set aside as CBM 

shall be zero in non-firm ATC calculations. 

70. Finally, the Commission required the transmission provider to design their 

transmission charges so that the class of customers not benefiting from the CBM setaside, i.e., point-to-point customers, do not pay a transmission charge that includes the 

cost of the CBM set-aside. Transmission providers were permitted to submit redesigned 

transmission charges that reflect the CBM set-aside through a limited issue FPA section 

205 rate filing. The Commission noted that these filings may be limited to the rate design 

change only, i.e., they would not require the submission of cost of service data or a 

revision to the transmission provider’s revenue requirement. 

Requests for Rehearing and Clarification 

71. Duke requests that the Commission clarify that utilities that do not reserve CBM 

for themselves do not need to make it available to others. Although the Commission 

required transmission providers to make CBM available to LSEs that request it, Duke 

argues that the Commission has no authority under FPA section 206 to require 

transmission providers to do so when they do not use CBM themselves since there is no 

potential for undue discrimination. 
Docket No. RM05-17-001, et al. - 39 -

72. With regard to the calculation of CBM, Southern argues that requiring a consistent 

calculation methodology would be harmful to LSEs because reserve needs vary from area 

to area. Southern contends that LSEs should be allowed the flexibility to establish CBM 

on a per-interface basis so that CBM use will be commensurate with expected system 

conditions, topography, and available capacity markets. Southern states, for example, 

that small LSEs typically have fewer internal resources than larger LSEs and therefore 

need more CBM. Southern contends that a consistent methodology could result in higher 

infrastructure cost, place system reliability at risk, and ultimately remove the economic 

benefit associated with CBM. 

73. Southern also argues that development of a “one-size-fits all” methodology for the 

calculation of CBM would be impossible due to varying regional and state mandates 

governing generation adequacy issues. Southern contends that such a mandate, if applied 

to a transmission provider’s native load customers that are under varying regional and 

state resource adequacy requirements, would amount to a regulation of reserve adequacy 

which is outside of the Commission’s jurisdiction. Southern adds that this would 

implicate (and may violate) the reliability provisions of FPA section 215 and the native 

load protections of FPA section 217. 

74. TDU Systems request that the Commission clarify, or grant rehearing, that if a 

transmission provider does not accommodate reserve-sharing arrangements for its loadserving transmission customers as TRM, then it must allow access to the CBM set-aside 

for reserve-sharing purposes. TDU Systems are concerned that some transmission 

providers do not use TRM set-asides, but rather use a CBM-approach to reserving 
Docket No. RM05-17-001, et al. - 40 -

capacity across interfaces for reserve-sharing arrangements. In such cases, TDU Systems 

state that LSEs needing access to interface capacity to accommodate reserve-sharing 

arrangements may not be able to obtain that capacity if the Commission limits such usage 

to TRM. TDU Systems contend that transmission providers set aside interface capacity 

to serve their retail native load in the case of both generation emergencies and economic 

transactions and that comparability demands the same for the reserve-sharing 

arrangements for LSEs. 

75. With regard to cost recovery of the CBM set-aside, Southern argues that CBM is a 

component of network service that is already paid for by network customers and native 

load through their bearing a load-ratio share responsibility for the costs of the 

transmission system. Southern contends that CBM is used as a network reservation of 

resources used to service network and/or native load under certain conditions. Southern 

argues that a network customer’s cost responsibility is based upon its load, not its 

designation of network resources and, therefore, the network customer is already bearing 

CBM-related costs through its load ratio share responsibility. 

76. As a result, Southern concludes that point-to-point customers are not paying for 

CBM capacity and, instead, are paying their appropriate share of the total transmission 

system cost based upon their reservations of capacity. Southern states that Commission 

policy requires network customers and native load to bear the costs of both the capacity 

they use and any capacity that is not reserved by point-to-point customers.42 Southern 

 42 Citing Order No. 888-A at P 30,220. 
Docket No. RM05-17-001, et al. - 41 -

argues that the Commission’s finding in Order No. 890 that point-to-point customers are 

inappropriately bearing the costs of CBM represents an unexplained departure from 

Order No. 888-A. 

77. Southern also contends that this ruling will result in an inconsistency within the 

pro forma OATT, requiring incremental cost responsibility for network customers to 

utilize one particular type of external resource or off-system purchase, i.e., the utilization 

of CBM. Southern argues that this conflicts with the structure of network service under 

the pro forma OATT, which allows the network customer to utilize the interfaces for both 

external designated network resources and off-system opportunity purchases without 

additional charge. Southern also contends that requiring network customers to pay for 

CBM on the same basis as firm point-to-point service disadvantages the use of CBM 

since interface capacity could only be used on an emergency basis and therefore is not 

considered firm service for the purpose of designating off-system system resources. 

78. Southern goes on to assert that the Commission’s premise that point-to-point 

customers are not benefiting from CBM is incorrect. Southern notes that under normal 

conditions the transfer capability reserved as CBM is made available for non-firm use by 

other customers. Southern notes also that long-term point-to-point customers benefit 

from the non-firm point-to-point use of that transfer capability because associated 

revenues are included as revenue credits in the numerator of the OATT rate calculations 

to reduce charges to long-term firm point-to-point customers. 

79. If the Commission does not reverse its decision in Order No. 890 regarding the 

redesign of transmission charges, Southern seeks clarification regarding how the CBM 
Docket No. RM05-17-001, et al. - 42 -

set-aside should be treated for ratemaking purposes since it does not represent additional 

load. Southern notes that the potential for long-term customers to receive a rate benefit 

from the non-firm point-to-point use of the set-aside raises the potential for them 

receiving a double credit. Southern also suggests that the Commission defer the new rate 

design filing until after NERC has adopted ATC standards under MOD-001. 

80. EEI and Idaho Power raise similar concerns, asking the Commission to clarify 

that, when the transmission provider modifies its rate design for point-to-point 

transmission service, it also may propose a rate design modification to ensure that it 

recovers from network and native load customers any reduction in revenues resulting 

from the change in the rates for point-to-point service. Duke contends that allocating 

costs of the CBM set-aside through a downward revision to point-to-point rates would 

have the effect of allocating costs to native load and network customers for a service that 

is not taken. EEI and Idaho Power argue that the Commission should allow transmission 

providers to modify their rates for other services in order to prevent under-recovery of 

their costs of service or inappropriately shifting costs to native load customers. EEI also 

requests the Commission to clarify that the rate design change may take into 

consideration the fact that transmission providers credit against the cost of service 

revenues received from short-term and non-firm transmission service provided using 

capacity that is set aside for CBM to ensure that long-term firm point-to-point customers 

do not receive a double credit for the use of CBM capacity. 

81. EEI requests further clarification regarding how a transmission provider should 

modify unit charges that are established by settlement. EEI argues that transmission 
Docket No. RM05-17-001, et al. - 43 -

providers should not be required to make an entirely new cost-of-service filing and, 

instead, should be permitted to reduce its rates for firm point-to-point service by the ratio 

of its current transmission load and reservations without the CBM set-aside to its 

transmission load and reservations plus the CBM set-aside. 

Commission Determination

82. The Commission clarifies in response to Duke that utilities do not need to make 

CBM available to LSEs on their system if the utilities do not reserve for themselves CBM 

or its equivalent. Comparability only requires transmission providers to make CBM 

available when they set aside for themselves transfer capability to meet generation 

reliability criteria.43 In order to provide transparency and consistency regarding the use 

of CBM, public utilities, working through NERC, must develop clear standards for how 

CBM is determined, allocated across transmission paths, and used.44 

83. The Commission did not mandate a particular methodology for allocating CBM 

over transmission paths and flowgates in Order No. 890. We therefore reject Southern’s 

argument that development of a consistent methodology for calculating CBM would be 

harmful to LSEs because reserve needs vary from area to area. While we expect the 

 43 We note that Duke states, in its Attachment C compliance filing, that it has set 

CBM on all of its interfaces to zero because it uses short-term line ratings (where 

available), which yields an operating margin that may be used for unexpected conditions 

or inaccuracies in data. See Compliance filing of Duke Energy Carolinas, Docket No. 

OA07-82-000 (Sep. 10, 2007); Open Access Transmission Tariff of Duke Energy 

Carolinas, LLC, FERC Electric Tariff Fifth Rev. Vol. No. 4, Original Sheet 170H. The 

Commission will address the merits of that practice in Docket No. OA07-82-000. 

44 Order No. 890 at P 256, 259. 
Docket No. RM05-17-001, et al. - 44 -

NERC and NAESB process to produce a consistent and transparent process for setting 

aside and allocating CBM based on LSE requests, we decline to prescribe a specific 

method for how CBM should be obtained or allocated or otherwise determine the amount 

of capacity that the transmission provider has to set aside in response to requests from 

multiple LSEs. 

84. We disagree that a consistent CBM methodology that allows LSEs access to 

historically used resources would impair reliability, conflict with the rights of native load 

under FPA section 217, or otherwise implicate varying regional and state mandates 

governing adequacy issues. In any event, it is premature to consider these questions since 

NERC and NAESB have yet to complete their work on the reliability standards and 

business practices. We also disagree with Southern that a consistent CBM methodology 

will remove the economic benefit associated with CBM. Rather, a consistent 

methodology for determining how the CBM value is determined, allocated, and used will 

remove excess discretion that transmission providers previously had and allow all LSEs 

to have the benefits associated with CBM. 

85. Regarding TDU Systems’ request to use CBM for reserve-sharing arrangements, 

we reiterate that TRM is the appropriate category for reserve-sharing arrangements and 

that CBM is to meet verifiable generation reliability criteria in times of emergency 

generation deficiencies.45 As the Commission explained in Order No. 890, TRM may be 

 45 See id. at P 264. 
Docket No. RM05-17-001, et al. - 45 -

used for other transmission-related uncertainties as well.46 Because the transmission 

provider may set aside transfer capability for TRM to operate the system reliably, we 

reject TDU Systems’ request to use CBM for reserve-sharing purposes. 

86. With regard to cost recovery of the CBM set-aside, we affirm the decision in 

Order No. 890 to require transmission providers to design their transmission charges to 

ensure that the class of customers not benefiting from the CBM set-aside, i.e., point-topoint customers, do not pay a transmission charge that includes the cost of the CBM setaside. Only network customers and the transmission provider on behalf of its native load 

may request that transmission capacity be set aside as CBM and, therefore, only those 

users of the system should bear its costs. We disagree with Southern that, because CBM 

is used by network customers, all the costs associated with CBM are already borne by 

network customers through their load ratio share responsibility. As Southern 

acknowledges, the rates for point-to-point service are also calculated based on a share of 

total transmission system cost. If the costs associated with CBM are not excluded from 

the universe of costs allocated to all point-to-point customers, then every point-to-point 

customer will end up paying a portion of those costs. The Commission’s rate design 

ruling is therefore consistent with, not contrary to, the Commission’s directive in Order 

No. 888-A for network customers and native load to bear the cost of capacity not used by 

point-to-point customers.47 

 46 See id. at P 273. 

47 See Order No. 888-A at 30,220. 
Docket No. RM05-17-001, et al. - 46 -

87. We acknowledge, as Southern claims, that point-to-point customers do reap some 

indirect benefits from the CBM set-aside in that related capacity that is not used is made 

available on a non-firm basis and that, in turn, can generate revenues that are credited to 

the transmission cost of service to the benefit of point-to-point customers. We do not 

believe this justifies charging all point-to-point customers for the cost of the CBM setaside. These costs should instead be allocated to the entities that have the exclusive right 

to request the set-aside in the first instance. We agree that, in certain circumstances, this 

may necessitate modification of other rate design elements to ensure that costs are 

appropriately allocated and that the transmission provider fully recovers any reduction in 

revenues resulting from the change in the rates for firm point-to-point service. Nothing 

in Order No. 890 precludes transmission providers from proposing modification of rates 

for other services (such as network service) as necessary to recover CBM-related costs 

previously paid by point-to-point customers. Similarly, we expect that transmission 

providers would address in their rate design filings any possibility for particular 

customers to receive an inappropriate credit for non-firm use of capacity set aside for 

CBM. 

88. We disagree that requiring transmission providers to design their rates to properly 

allocate CBM-related costs conflicts with the nature of network service or disadvantages 

network customers using CBM. Under the pro forma OATT, transfer capability is made 

available for network resource designations and firm point-to-point reservations on a 

non-discriminatory basis. It is therefore appropriate to design rates so that network 

customers and point-to-point customers pay rates based on the service available to each. 
Docket No. RM05-17-001, et al. - 47 -

89. We decline to defer the filing of CBM-related rate design proposals until 

completion of the NERC/NAESB standardization process. To the extent a transmission 

provider’s rates currently collect the costs associated with the CBM set-aside from pointto-point customers, those rates must be redesigned in accordance with Order No. 890. 

We acknowledge, however, that the on-going NERC and NAESB standardization 

processes may result in CBM being set aside and used differently in the future. To the 

extent such changes implicate the allocation of costs among those that are eligible to 

request or use the set-aside, the transmission provider should file with the Commission 

any necessary rate changes to ensure that CBM costs continue to be allocated 

appropriately. 

90. Finally, we decline to address here what changes may be necessary to a particular 

rate settlement in order to ensure that costs associated with the CBM set-aside are 

allocated properly. All proposals to allocate CBM costs will be considered on a case-bycase basis, whether they involve rates stated in a settlement or otherwise. 

 (3) TRM

91. The Commission required public utilities, working through NERC, to complete the 

ongoing process of modifying TRM-related reliability standards (MOD-008 and MOD009). To guide NERC and NAESB in the process of drafting TRM-related standards and 

business practices, the Commission explained that transmission providers may set aside 

TRM for (1) load forecast and load distribution error, (2) variations in facility loadings, 

(3) uncertainty in transmission system topology, (4) loop flow impact, (5) variations in 

generation dispatch, (6) automatic sharing of reserves, and (7) other uncertainties as 
Docket No. RM05-17-001, et al. - 48 -

identified through the NERC reliability standards development process. To the extent 

capability is needed for transmission of shared reserves, the Commission stated that it 

must be included in TRM, although the Commission did not mandate the use of reserve 

sharing groups. 

92. Each transmission provider was required to calculate, and allocate on the paths 

and flowgates, the aggregate TRM value for all LSEs within its area. Public utilities also 

were directed, working through NERC, to establish an appropriate maximum TRM. The 

Commission expressed support for NERC’s plan to revise existing reliability standards 

for TRM to require clear documentation of the TRM calculation, to ensure full 

transparency. In addition, the Commission required each transmission provider to make 

available all underlying documentation, including work papers and load flow base cases, 

used to determine TRM, to any transmission customer and LSE within its control area, 

subject to a confidentiality agreement,48 if necessary. Because load, facility loadings, and 

other uncertainties constantly deviate, the Commission did not require that TRM set-aside 

capacity be sold on a non-firm basis. The Commission explained that any request for 

regional difference from the applicable TRM reliability standards must take place 

through the NERC reliability standards development process. 

 48 The confidentiality agreement may appropriately restrict the sharing of sensitive 

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

opposed to merchant functions. 
Docket No. RM05-17-001, et al. - 49 -

Requests for Rehearing and Clarification

93. Duke asks the Commission to clarify that it intended NERC to develop a 

methodology to calculate a maximum TRM number, not to put an actual number in the 

reliability standard, arguing that requiring an actual number would overstep the bounds of 

FPA section 215. Southern argues that NERC must be allowed flexibility to develop 

appropriate TRM methodologies so that the use of TRM will be commensurate with 

expected system conditions, topography, and available capacity markets. Southern 

contends that setting a maximum amount of TRM would overlook the physical realities 

of the differing system configurations that constitute the electrical system. Southern 

argues, in particular, that the percentage ratings reduction proposed would be poorly 

suited as a reliability margin since individual line flows can change by very large 

percentages for single contingency events. 

Commission Determination

94. The Commission clarifies that NERC was not directed to identify an actual 

number or a particular methodology to include in the TRM standards, MOD-008-0 and 

MOD-009-0. The Commission’s intent was to require NERC and NAESB to include 

consistent criteria and guidelines in the calculation and uses of TRM by transmission 

providers.49 Likewise, in response to Southern’s concern regarding flexibility to use 

something other than the ratings reduction method discussed in Order No. 890, we clarify 

that the ratings reduction method is only an example of a simple method that could be 

 49 See Order No. 890 at P 273. 
Docket No. RM05-17-001, et al. - 50 -

used.50 Our intent is not to prohibit a transmission provider from using a more 

sophisticated method, so long as it is consistent with the reliability standards developed 

by NERC. 

e. Modeling, Assumptions and Input Data

95. The Commission directed public utilities, working through NERC, to modify the 

reliability standards MOD-010 through MOD-02551 to incorporate a requirement for the 

periodic review and modification of models for (1) load flow base cases with 

contingency, subsystem, and monitoring files, (2) short circuit data, and (3) transient and 

dynamic stability simulation data, in order to ensure that these models are up to date. The 

Commission stated that the models should be updated and benchmarked to actual events. 

96. The Commission also required transmission providers to use consistent data and 

assumptions underlying operational planning for short-term ATC and expansion planning 

for long-term ATC calculation, to the maximum extent practicable. The Commission 

explained that such data and assumptions include, for example, (1) load levels, 

(2) generation dispatch, (3) transmission and generation facilities maintenance schedules, 

(4) contingency outages, (5) topology, (6) transmission reservations, (7) assumptions 

regarding transmission and generation facilities additions and retirements, and 

 50 See id. at P 275. 

51 The MOD-010 through MOD-025 reliability standards establish data 

requirements, reporting procedures, and system model development and validation for 

use in the reliability analysis of the interconnected transmission systems. 
Docket No. RM05-17-001, et al. - 51 -

(8) counterflows. The Commission directed public utilities, working through NERC, to 

modify ATC standards to achieve this consistency. 

Requests for Rehearing and Clarification

97. Entergy requests that the Commission acknowledge that the benchmarking of 

ATC calculations to real-time ATC values is only one piece of information to be used to 

evaluate ATC practices. Entergy agrees that such updating and benchmarking can 

provide information related to ATC/AFC calculations, but states that differences between 

the models used to calculate ATC/AFC and actual events in fact are going to occur. 

Entergy contends that the purpose of the ATC/AFC models is not to forecast actual 

operating conditions, but instead to reflect the physical transmission rights that have been 

previously granted and to determine if additional physical rights may be granted.52 

Entergy argues that benchmarking may be helpful when evaluating ATC, but it will not 

tell the whole story. 

98. TDU Systems request that the Commission explicitly state that assumptions 

regarding loop flows must be consistent for ATC calculation and planning purposes, 

 52 Entergy asserts that actual conditions will and should deviate from ATC/AFC 

models for numerous reasons. Entergy states that transmission operators are constantly 

monitoring their systems and taking actions to ensure that system constraints are 

mitigated well before real-time, including modifications to transmission outage plans, 

generator outage plans, and daily unit commitment plans. Entergy contends that those 

actions could, for example, make a flowgate that months ahead of time was predicted to 

be loaded at 100 percent to be loaded less than 50 percent in real-time. Entergy also 

notes that many transmission customers only use all of their transmission rights a small 

percentage of the time and, in any event, actual operating ATC will not perfectly match 

posted ATC since, for example, the level of mandatory purchases from qualifying facility 

(QF) can affect real-time ATC. 
Docket No. RM05-17-001, et al. - 52 -

within the respective timeframe. TDU Systems argue that consistency in modeling the 

effects of those loop flows is necessary to ensure that neighboring transmission systems 

have accurately calculated ATC not only on their own systems but also on their interfaces 

with other systems. TDU Systems also ask that the Commission clarify that the 

assumptions and data to be used in ATC modeling must include the native load service 

obligations of LSEs as well as the transmission provider’s native load. 

Commission Determination

99. The Commission clarifies in response to Entergy that the models used by the 

transmission provider to calculate ATC, and not actual ATC values, must be 

benchmarked. The Commission is concerned with the level of accuracy of the models 

and, therefore, directed in Order No. 890 that the models be updated and benchmarked to 

actual events. If models are not sufficiently accurate, then ATC/AFC calculations will 

not generate correct results, undermining the benefits of increased consistency and 

transparency of ATC calculations. With regard to discrepancies between actual and 

modeled ATC values, the Commission directed the ERO in Order No. 693 to modify 

MOD-014-0 through the reliability standards development process to require that actual 

system events be simulated and, if the model output is not within the accuracy required, 

the model shall be modified to achieve the necessary accuracy. 

100. We agree with TDU Systems that assumptions regarding loop flows in calculating 

ATC must be consistent with those used for planning purposes within the respective 

timeframes. We also agree that loop flow impact in ATC calculation should not be 

restricted to the transmission provider’s control area. Loop flows that occur in the power 
Docket No. RM05-17-001, et al. - 53 -

system must be included in the load flow models that simulate power system conditions. 

Loop flows affecting ATC calculation should be taken into account consistently by using 

the same models and assumptions as used for the planning of the system. With regard to 

modeling LSE uses of the system, we clarify that each transmission provider must 

include the native load service obligations of LSEs as well as the transmission provider’s 

own load in modeling assumptions and data used for ATC calculation. 

f. ATC Calculation Frequency

101. The Commission directed public utilities, working through NERC and NAESB, to 

revise reliability standard MOD-001 to require ATC to be recalculated by all 

transmission providers on a consistent time interval and in a manner that closely reflects 

the actual topology of the system, e.g., generation and transmission outages, load 

forecast, interchange schedules, transmission reservations, facility ratings, and other 

necessary data. The Commission stated that this process must also consider whether 

ATC should be calculated more frequently for constrained facilities. 

Requests for Rehearing and Clarification

102. Powerex asks the Commission to clarify that transmission providers are required 

to update their ATC calculations when they receive new data otherwise required to be 

posted under the requirements of Order No. 890, such as updated load forecasts. 

Powerex argues that the standards adopted through the NERC and NAESB processes 

should serve only as minimum or "no less frequent than" requirements. In Powerex’s 

view, the specification of consistent intervals for ATC calculations should not prohibit or 

deter transmission providers from calculating and posting ATC on a more frequent basis 
Docket No. RM05-17-001, et al. - 54 -

as new data becomes available, particularly in light of the Commission's goal in Order 

No. 890 to make the ATC calculation process more transparent to customers. 

103. Southern asks the Commission to clarify that ATC, not TTC, must be recalculated 

at consistent time intervals. Although the Commission referenced ATC in Order No. 

890, Southern contends that the associated data and assumptions mentioned by the 

Commission (generation and transmission outages, load forecast, interchange schedules, 

transmission reservations, facility ratings, and other necessary data) relate to TTC. 

Southern argues that ATC is the appropriate reference because it can be calculated 

automatically with relative ease and frequency. In comparison, Southern states that TTC 

requires much more complex power flow analyses and should not be driven by changes 

in parameters without expert review. Southern contends that the calculation frequency 

requirements established by the Commission would result in constantly changing values 

if applied to TTC, with little time, if any, for the necessary review. 

Commission Determination

104. The Commission agrees with Powerex that the standards adopted through the 

NERC and NAESB processes should serve as minimum or "no less frequent than" 

requirements to recalculate ATC. Transmission providers also must update their ATC 

calculation when they receive substantial and material changes in data, such as updated 

load forecasts, changes in topology and dispatch patterns, which may be more frequent 

than the NERC and NAESB standards would otherwise require. In the absence of 

substantial and material changes in data, transmission providers are not required to 

update ATC on a more frequent basis than the minimum frequency that the NERC and 
Docket No. RM05-17-001, et al. - 55 -

NAESB standards require, once implemented. The Commission will consider the 

adequacy of the time frame for ATC updates on review of these standards. 

105. In response to Southern, we reiterate that Order No. 890 directed revisions to 

reliability standard MOD-001 to require that ATC, not TTC, be recalculated at consistent 

time intervals.53 However, system topology or other changes such as transmission 

outages, load forecast, interchange schedules, transmission reservations, or facility 

ratings, and other necessary data that affect ATC may of course impact one or more of 

the components of ATC, including TTC. While we agree with Southern that TTC 

requires more involved power flow analyses, the transmission provider should consider 

whether any changes in system topology, contingency outages, or other factors are 

substantial enough to merit recalculation of TTC. 

2. Transparency

106. In Order No. 890, the Commission adopted a number of requirements in order to 

improve the transparency of ATC calculations. Some of these reforms applied to the pro 

forma OATT, including a requirement that each transmission provider include in 

Attachment C to its OATT more descriptive information concerning its ATC/AFC 

calculation methodology. Other reforms applied to information posted on OASIS, 

including data related to the calculation of ATC and TTC, changes in the ATC/TTC 

values, disclosure of Critical Energy Infrastructure Information (CEII), and the posting of 

 53 See Order No. 890 at P 301. 
Docket No. RM05-17-001, et al. - 56 -

additional ATC-related data. Petitioners have requested rehearing and clarification of 

certain of these requirements, which we address in turn. 

a. OATT Transparency – Attachment C 

107. To increase transparency regarding ATC calculations, the Commission directed 

each transmission provider to set forth its ATC calculation methodology in Attachment C 

to its OATT. The Commission required that each transmission provider’s Attachment C 

must, at a minimum: (1) clearly identify which of the NERC-approved methodologies it 

employs (e.g., contract path, network ATC, or network AFC); (2) provide a detailed 

description of the specific mathematical algorithm the transmission provider uses to 

calculate firm and non-firm ATC for the scheduling horizon (same day and real-time), 

operating horizon (day ahead and pre-schedule), and planning horizon (beyond the 

operating horizon); (3) include a process flow diagram that describes the various steps 

that it takes in performing the ATC calculation; (4) set forth a definition of each ATC 

component (i.e., TTC, ETC, TRM, and CBM) and a detailed explanation of how each one 

is derived in both the operating and planning horizons; and, (5) document their processes 

for coordinating ATC calculations with their neighboring systems. 

108. The Commission concluded that Attachment C must provide an accurate 

documentation of processes and procedures related to the calculation of ATC, not the 

actual mathematical algorithms, which instead should be posted on their web site with the 

link noted in the Attachment C. The Commission noted that a transmission provider may 

require a confidentiality agreement for CEII materials, consistent with our CEII 

requirements, or may otherwise protect the confidentiality of proprietary customer 
Docket No. RM05-17-001, et al. - 57 -

information. The Commission also required transmission providers to file a revised 

Attachment C to incorporate any changes in NERC’s revised reliability standards and 

NAESB’s business practices related to ATC calculations, as requested by the 

Commission in Order No. 890, within 60 days of completion of the NERC and NAESB 

processes. 

Requests for Rehearing and Clarification

109. MidAmerican objects to the Commission’s decision to require a process flow 

diagram to be included in Attachment C, suggesting instead that each transmission 

provider post this information on its website as an alternative. MidAmerican contends 

that process flow diagrams demand large amounts of computer capacity and that 

management of and electronic transmittal of its OATT would become difficult if process 

flow diagrams were required for other elaborate and important tasks throughout the tariff, 

such as the transmission service request procedure or the generation interconnection 

procedure. MidAmerican argues that providing a web link on OASIS would achieve the 

Commission's transparency objective and expeditiously provide those that wish to 

navigate through a process diagram a direct access to the document. At a minimum, 

MidAmerican asks that the Commission accept an internet posting of the diagram with 

the web address published in Attachment C. 

110. Southern requests clarification as to whether the Commission intends for 

transmission providers to make two filings of ATC methodologies (i.e., one when the 

Order No. 890 becomes effective and another when the NERC and NAESB processes are 

completed) or just one filing of such methodologies (i.e., a single filing when the NERC 
Docket No. RM05-17-001, et al. - 58 -

and NAESB processes are completed). Southern argues that only one filing should be 

required, to be made within 60 days after the NERC and NAESB processes are 

completed. Southern contends that requiring a premature filing before those processes 

are complete would waste transmission providers’ resources in preparing those filings 

and the Commission’s resources in reviewing them. 

Commission Determination

111. The Commission denies MidAmerican’s request to permit a transmission provider 

to post on its website a process flow diagram and provide a web address in Attachment C, 

instead of providing the process flow diagram as a part of the Attachment C. A link to a 

website is not the equivalent of inclusion in the transmission provider’s OATT, leaving 

the Commission unable to enforce use of the process flow diagram and the public with 

potentially more limited notice of any changes to the process flow diagram. The 

transparency and enforceability benefits of including the flow diagram in the tariff 

outweigh any potential filing burden. Therefore, we affirm our determination in Order 

No. 890 that a process flow diagram must be filed with OATT Attachment C, and that 

any change of the processes or data information identified by the process flow diagram 

must trigger an update of the process flow diagram and the filing of the revised OATT, 

Attachment C. 

112. In response to Southern, Order No. 890 specifically required transmission 

providers to submit an intermediate filing within 180 days after the publication of the 

order in the Federal Register in order to provide transparency of the transmission 

provider’s existing ATC calculation methodologies. In compliance with that 
Docket No. RM05-17-001, et al. - 59 -

requirement, a number of transmission providers, including Southern, submitted 

Attachment C compliance filings on September 11, 2007. The immediate transparency 

benefits of these filings will be supplemented by a revised filing following completion of 

the NERC and NAESB standardization processes. We do not believe the intermediate 

filing represented an undue burden to the transmission providers, as it was no more than a 

documentation of existing practices. 

b. OASIS

(1) ATC/TTC Posting Requirements

113. The Commission concluded that transmission providers must continue to comply 

with existing ATC-related posting requirements, as supplemented by Order No. 890. To 

that end, the Commission stated that it would maintain a requirement for transmission 

providers to make available, upon request, all data used to calculate ATC and TTC for 

any constrained paths and any system planning studies or specific network impact studies 

performed for customers. Transmission providers were also directed to continue to post a 

list of such studies on OASIS. The Commission required the additional posting of, at a 

minimum, a list of all system impact studies, facilities studies, and studies performed for 

the transmission provider’s own network resources and affiliated transmission customers, 

with those studies to be made available upon request. The Commission noted that 

appropriate procedures to accommodate CEII concerns should be developed to ensure 

eligible entities with a legitimate interest in transmission study data can receive access to 

it. The Commission required that the studies be made available for five years, consistent 

with data retention requirements pertaining to denial of service requests. 
Docket No. RM05-17-001, et al. - 60 -

Requests for Rehearing and Clarification

114. MidAmerican requests clarification with regard to the interaction of the data 

availability obligation under Order No. 890 and the Commission’s Standards of Conduct 

with respect to information requests made by affiliated transmission customers. In order 

to provide comparable transmission service, MidAmerican argues that data must be 

available in all circumstances. If the Commission does not clarify that this is the case, 

MidAmerican requests rehearing of this provision so that comparable information can be 

made available at all times. 

Commission Determination

115. The Commission clarifies that all data used to calculate ATC and TTC for any 

constrained paths and any system planning studies or specific network impact studies 

performed for customers are to be made available on request, regardless of whether the 

customer is non-affiliated or affiliated with the transmission provider. To the extent the 

requesting party is an affiliate, the Standards of Conduct would require that data provided 

to the affiliate be simultaneously posted on the transmission provider’s OASIS or 

website, as applicable.54 

(2) ATC/TTC Narrative Explanation

116. The Commission retained existing posting requirements for unconstrained paths 

and amended its regulations relating to data posted for constrained paths. Specifically, 

the Commission required transmission providers to post a narrative when a monthly or 

 54 See 18 CFR 358.5. 
Docket No. RM05-17-001, et al. - 61 -

yearly ATC value changes as a result of a 10 percent change in TTC on constrained 

paths. Posted information must include both the (1) specific events which gave rise to the 

change and (2) the new values for ATC on that path (as opposed to all points on the 

network). The Commission also required the posting of a narrative with regard to 

monthly or yearly ATC values when ATC remains unchanged at a value of zero for a 

period of six months or longer. 

Requests for Rehearing and Clarification

117. E.ON U.S. argues that the posting of a narrative explanation for changes in ATC 

resulting from changes in TTC is unduly burdensome and, in any event, would not 

provide transmission customers with any meaningful information. E.ON U.S. contends 

that, using the new process for calculating TTC, a transmission provider would have to 

calculate the value for each horizon model and compare it to values in the previous hour 

in order to implement the posting requirement. Where those values change by more than 

10 percent, E.ON U.S. states that the transmission provider will have to examine 

individually each changed parameter to assess its contribution to the change. E.ON U.S. 

contends that, for its system, the list of parameters to be evaluated would include 

generation dispatch, system configuration, loads, and net interchanges of which there can 

be dozens or even hundreds per hour. E.ON U.S. argues that this would take 24 

engineers to monitor the E.ON U.S. system alone, costing millions of dollars per year. 

118. Southern requests that the Commission clarify that the required narratives do not 

need to list each and every circumstance or occurrence that impacts TTC values from the 

previous month or year, stating that such a list would likely be voluminous because of the 
Docket No. RM05-17-001, et al. - 62 -

many conditions that affect TTC. Southern instead suggests that transmission providers 

list the primary reasons for the change in TTC to the extent they are known. Southern 

contends, for example, that an appropriate reason for such changes would be a new 

updated monthly model, arguing that it would not be practical to determine how much 

TTC may change from each outage, service commitment or other parameter change 

incorporated in an updated model. 

119. Southern also requests that the Commission clarify where the transmission 

provider should post these narrative explanations and in what form. Southern proposes 

that this information be posted on OASIS via a template and data element that is to be 

defined by a NAESB standard, incorporated into a revised Standards and 

Communications Protocol document, and subsequently adopted by the Commission. 

120. TDU Systems argue that the Commission has set too high of a threshold for 

reporting changes in ATC/TTC, arguing that the triggering requirement should be a 10 

percent decrease in ATC, rather than a 10 percent change in TTC. TDU Systems contend 

that TTC is a large enough number that using a decrease of 10 percent in TTC as a trigger 

for requiring a narrative explanation to be posted will result in very few narrative 

explanations posted, thereby defeating the purpose of the requirement. 

121. PJM seeks clarification of the posting requirement as applied to transmission 

providers using an AFC calculation method. PJM states that TTC is an output from, not 

an input to, its AFC/TTC calculations and therefore the literal terms of the regulations do 

not make sense as applied to PJM. PJM proposes to post a narrative explanation for the 

reason for daily changes in ATC or TTC values as a result of changes in AFC inputs (i.e., 
Docket No. RM05-17-001, et al. - 63 -

transmission outages, generator outages, load forecast, and model updates) in the event 

the resultant ATC or TTC value changes by 10 percent or more, requesting that the 

Commission confirm that this approach would appropriately adapt the Order No. 890 

posting requirement to a system such as PJM that uses an AFC methodology. 

Alternatively, if the Commission does not wish to address PJM’s manner of 

implementation of this revised regulation in the context of rehearing/clarification of 

Order No. 890, PJM asks that the Commission allow PJM, and other similarly situated 

transmission providers, to address this issue in their Order No. 890 tariff compliance 

filings. In that event, PJM asks that the Commission clarify only that such transmission 

providers may continue their existing practices until the Commission acts on their 

compliance filings. 

122. TDU Systems also argue that the six-month trigger for posting an explanation for 

zero ATC values is unsupported, asking instead that transmission providers be required to 

post a narrative explanation of zero ATC values any time those values remain at zero for 

a period that affects access in a practical way, e.g., a day for daily service, two business 

days for weekly service, five business days for monthly or yearly service. TDU Systems 

contend that a transmission system where ATC values remain at zero for any length of 

time raises serious concerns as to the adequacy of the system and the need for significant 

upgrades, and simply posting a zero value for ATC does not provide market participants 

with an understanding of what is happening on the system. 
Docket No. RM05-17-001, et al. - 64 -

Commission Determination

123. The Commission affirms the decision in Order No. 890 to require transmission 

providers to post a brief, but specific, narrative explanation of the reason for a change in 

monthly or yearly ATC values on a constrained path as a result of a change in TTC of 10 

percent or more. As the Commission explained, this will limit the number of ATC 

changes for which a narrative will be required.55

124. We believe that E.ON U.S. overestimates the burden of complying with this 

requirement. Since TTC standardization is ongoing, it is impossible to identify with 

precision the steps that will need to be taken to comply with the posting requirement. 

The appropriate forum to raise concerns regarding the burden of particular TTC 

calculation requirements is in the NAESB standards development process. In any event, 

we would expect that the posting of narratives for changes in monthly and yearly ATC 

values as a result of a 10 percent change in TTC will be triggered mainly by topology 

changes resulting from transmission lines and generator in-service status, as well as new 

facilities additions, that are reported on OASIS. 

125. We clarify in response to Southern that transmission providers do not need to list 

each and every circumstance or occurrence that impacts TTC values from the previous 

month or year and, instead, may list the primary events that give rise to the update. 

Again, we expect that TTC changes will generally result from topology changes and, 

therefore, the primary reasons for an update would be changes in schedules of 

 55 See Order No. 890 at P 369. 
Docket No. RM05-17-001, et al. - 65 -

transmission or generation additions, prolonged outages, or changes in maintenance 

schedules causing a TTC change of 10 percent. We agree with Southern that the 

transmission provider should post these narrative explanations on OASIS via a template 

and data element that is to be defined by NAESB. We direct transmission providers, 

working through NAESB, to develop the OASIS functionality necessary for such 

postings. Pending completion of this work by NAESB, we direct transmission providers 

to post these narrative explanations as comments on OASIS. 

126. We deny TDU Systems’ request to change the triggering requirement to a 10 

percent decrease in ATC. In Order No. 890, the Commission relaxed the ATC narrative 

reporting requirements proposed in the NOPR due to concerns that the posting of those 

narratives would become burdensome. We believe the Commission struck the right 

balance by requiring the posting of narratives only when there is a change in TTC of 10 

percent or more and disagree that more limited postings defeats the purpose of the 

posting obligation. 

127. In response to PJM, we reiterate that all transmission providers must comply with 

this posting requirement. Transmission providers using an AFC calculation method that 

does not base changes in ATC on changes in TTC may comply with this requirement by 

posting narrative explanations of the reasons for changes in AFC values as a result of 

changes in AFC inputs that cause ATC or TTC to change by 10 percent or more. We 

direct each transmission provider that employs the AFC calculation methodology to 

provide a statement in the compliance filing required in section II.C describing how the 
Docket No. RM05-17-001, et al. - 66 -

narrative is derived for ATC/TTC postings or, if such information was provided in a prior 

compliance filing, a reference to that filing. 

128. We also deny TDU Systems’ request to require transmission providers to post a 

narrative explanation any time ATC values remain at zero for a day for daily service, two 

business days for weekly service, five business days for monthly or yearly service. The 

Commission concludes that a six-month trigger for monthly or yearly ATC values more 

appropriately balances the benefits of increased transparency for the Commission and 

customers against the burden on transmission providers to make such postings. If the 

frequency of these postings proves inadequate, the Commission can revisit this 

requirement in a future order. 

(3) CEII

129. The Commission acknowledged in Order No. 890 that certain data and studies 

required to be made public may contain CEII and that the Commission has a 

responsibility to protect that information. In order to provide transparency and avoid 

undue delays in providing information to those with a legitimate need for it, the 

Commission required that transmission providers establish a standard disclosure 

procedure for CEII required to be disclosed in Order No. 890. The Commission stated 

that transmission providers will be responsible for identifying CEII and facilitating access 

to it for appropriate entities and the Commission will be available to resolve disputes if 

they arise. 

130. With regard to procedures to access CEII, the Commission noted that transmission 

customers already have digital certificates or passwords to access publicly restricted 
Docket No. RM05-17-001, et al. - 67 -

transmission information on OASIS. The Commission suggested that transmission 

providers could set up an additional login requirement for users to view CEII sections of 

the OASIS, requiring users to acknowledge that they will be viewing CEII and to sign a 

nondisclosure agreement at the time the customer obtains access to that portion of the 

OASIS. The Commission explained that only information that meets the criteria for 

CEII, as defined in section 388.113 of the Commission’s regulations,56 should be posted 

in this section of the OASIS. 

Requests for Rehearing and Clarification

131. E.ON U.S. contends that the Commission should not allow posting of CEII on 

OASIS, arguing that information is designated as CEII because it relates to the integral 

operations of the nation-wide power grid and that, with access to this information, a 

terrorist or other bad actor could inflict real, substantial harm on the power grid. E.ON 

U.S. states that posting CEII on a transmission provider’s OASIS, a website that is 

openly connected to the internet, will impair the transmission provider’s ability to 

adequately protect this information, even with password protection. E.ON U.S. suggests 

there are other ways of providing transmission customers with such CEII, such as 

individual meetings upon request. 

132. New York Transmission Owners request that transmission providers be authorized 

to determine, on a case-by-case basis, the specific level and amount of CEII that a 

requesting customer may obtain. New York Transmission Owners argue that a terrorist 

 56 18 CFR 388.113. 
Docket No. RM05-17-001, et al. - 68 -

seeking to harm our country’s energy infrastructure will not likely be concerned with 

having to sign a confidentiality agreement or obtain multiple passwords. 

Commission Determination

133. We agree with E.ON U.S. that posting CEII on OASIS may not provide adequate 

protection of CEII and that transmission providers may therefore develop other standard 

disclosure procedures to provide relevant CEII to transmission customers on a timely 

basis. The Commission did not require CEII postings on OASIS in Order No. 890 and, 

instead, discussed use of OASIS as one potential disclosure mechanism.57 The 

Commission required transmission providers to establish a standard procedure for 

disclosing relevant CEII on a timely basis, but did not specify a particular disclosure 

mechanism. 

134. Similarly, transmission providers may determine on a case-by-case basis the 

specific level of CEII a customer may obtain, provided that the information is made 

available to appropriate recipients on a timely basis. If a transmission provider chooses 

to post CEII on a protected section of its OASIS, the transmission provider can and 

should verify the identity of transmission customers who access that information as it 

would for any confidential information. 

(4) Additional Data Posting

135. The Commission also required transmission providers to post on OASIS metrics 

related to the provision of transmission service under the OATT. Specifically, non-

 57 See Order No. 890 at P 404. 
Docket No. RM05-17-001, et al. - 69 -

ISO/RTO transmission providers were directed to post (1) the number of affiliate versus 

non-affiliate requests for transmission service that have been rejected and (2) the number 

of affiliate versus non-affiliate requests for transmission service that have been made. 

This posting must detail the length of service request (e.g., short-term or long-term) and 

the type of service requested (e.g., firm point-to-point, non-firm point-to-point or network 

service). The Commission stated that the affiliate posting requirements do not apply to 

ISOs and RTOs since they do not have any affiliates. 

136. The Commission also required transmission providers to post their underlying load 

forecast assumptions for all ATC calculations and to post, on a daily basis, their actual 

daily peak load for the prior day and load forecasts and actual daily peak load for both 

system-wide load (including native load) and native load. ISOs and RTOs are required to 

post this load data for the entire ISO/RTO footprint and for each LSE or control area 

footprint within the ISO/RTO. 

Requests for Rehearing and Clarification

137. E.ON LSE requests clarification whether the requirement in section 37.6(e)(2) of 

the Commission’s regulations to post information regarding denials of service applies to 

denials of requests. Washington IOUs request clarification on the requirement to post 

information regarding transmission service requests from affiliates, stating that it is not 

clear what the Commission means by “requests for transmission service.” They suggest 

that the reference could be to requests for transmission service by affiliated merchant or 

trading entities or requests for transmission service by the transmission provider’s 
Docket No. RM05-17-001, et al. - 70 -

merchant function, including requests to designate or undesignate network resources and 

requests to procure secondary network service to serve native load. 

138. TDU Systems request that the Commission reconsider its decision to exempt 

RTOs and ISOs from the requirement to post data regarding their processing of 

transmission service requests. Although RTOs and ISOs have no generation affiliates, 

TDU Systems argue that requiring RTOs and ISOs to post information as to the number 

of requests made and rejected would make the acquisition of transmission services more 

transparent, serve as a signal for potential congestion problems on the system that should 

be studied through the planning process, and alert market participants to the emergence of 

market power in local submarkets. 

139. Constellation requests that the Commission clarify that the requirement to post 

underlying load forecast assumptions includes a complete list of modeling assumptions, 

protocols and automation modifications, including what the adjustments are and how they 

are applied. Constellation states that it requested that such information be required in its 

NOPR comments, but that it is unclear whether the requirement in Order No. 890 is 

broad enough to reflect that request. 

140. E.ON LSE requests that the Commission grant rehearing to permit utilities to 

decline to publicly post information regarding actual load and forecasts where such 

information is commercially sensitive or where customer-specific information is deemed 

confidential by the affected customer. E.ON LSE requests that such commercially 

sensitive information instead be posted four weeks after the time period that the data 

covers. E.ON LSE contends that disclosure of customer-specific load forecasts could 
Docket No. RM05-17-001, et al. - 71 -

have adverse competitive effects, such as a daily forecast signaling to sellers that a utility 

is in substantial need for additional energy during the upcoming day’s operations. E.ON 

LSE contends that the goal of transparency is sufficiently met even with a slight delay in 

posting commercially sensitive forecasts and load data. 

Commission Determination

141. In Order No. 890, the Commission required transmission providers to post on 

OASIS metrics regarding transmission service requests. The Commission did not 

distinguish between types of requests for transmission service. Transmission providers 

therefore should include in their metrics any type of request for service, including 

transmission service requests by affiliated merchant or trading entities as well as requests 

by the transmission provider’s merchant function to designate or undesignate network 

resources or to procure secondary network service to serve native load. We revise our 

regulations to make this clear. 

142. In response to TDU Systems, we clarify that Order No. 890 did not exempt RTOs 

and ISOs from the requirement to post metrics related to the provision of transmission 

service. While the affiliate posting requirements do not apply to RTOs and ISOs,58 the 

requirement to post metrics regarding all transmission service requests remains.59 We 

agree with TDU Systems that requiring RTOs and ISOs to post non-affiliate transmission 

 58 See Order No. 890 at P 414. 

59 See 18 CFR 37.6(i)(1) and (2). 
Docket No. RM05-17-001, et al. - 72 -

service request metrics improves the transparency of transmission service request 

processing by those transmission providers. 

143. In response to Constellation, we clarify that underlying load forecast assumptions 

should include economic and weather-related assumptions. We revise our regulations to 

clearly state the obligation to post both actual daily peak load and load forecast data, as 

required in Order No. 890.60 We decline to adopt E.ON LSE’s request to delay release of 

load data required to be posted in Order No. 890. Posting load forecast and actual load 

data on a control area and LSE level provides necessary transparency to transmission 

customers and does not, in our view, raise serious competitive implications.61 If there is 

customer-specific information deemed confidential by the affected customer that impedes 

the ability of the transmission provider to post this data, we will consider requests for 

exemption from the posting requirement on a case-by-case base. 

(5) Requests for Additional Transparency

Requests for Rehearing and Clarification

144. Constellation repeats a request from its NOPR comments to require transmission 

providers to post certain additional modeling data, modeling support information, and 

model benchmarking and forecasting data/TSR study audit data (identified in an 

attachment to its request for rehearing). Constellation argues that, since Order No. 890 

requires transmission providers to calculate much of this additional information, the 

 60 See Order No. 890 at P 416. 

61 See id. at P 417. 
Docket No. RM05-17-001, et al. - 73 -

Commission should require that it be posted as well. Constellation contends that these 

postings would allow transmission customers and the Commission to assess the likely 

availability of transmission capacity, verify or challenge the conclusions reached by the 

transmission provider on a specific transmission request, and identify constraints and 

congestion, as well as physical or financial measures that could be taken to optimize the 

use of transmission system. 

145. EPSA asks the Commission to clarify that the standards developed during the 

NAESB process should require transmission providers to post essential details of ETCs 

that affect current customers' access to transmission capacity, including duration and 

volume, priority rights, redispatch and scheduling rights, and any other rights that affect 

others' use of the grid. As part of these postings, EPSA suggests that transmission 

providers be required to include information concerning transmission arrangements that 

are not provided under the OATT, e.g., pre-OATT transmission arrangements. EPSA 

argues that non-OATT transmission arrangements often include terms that are 

inconsistent with OATT terms and which can impact OATT customers’ access to the 

grid. Unless transmission providers are required to post ETC-related information, EPSA 

contends that there will be no way for market participants to determine whether the 

transmission provider has appropriately modeled ETC set-asides. 

146. Powerex makes a similar request, reiterating a NOPR proposal that the 

Commission require transmission providers to post those provisions of pre-Order No. 888 

contracts that affect current customers’ access to transmission capacity, including 

duration and volume, priority rights, redispatch and scheduling rights, and any other 
Docket No. RM05-17-001, et al. - 74 -

rights that affect transmission access. Powerex further requests that the Commission 

prohibit the continuation of grandfathered contracts unless the parties can point to a 

provision within the existing contract that contains explicit and guaranteed rights to 

extend or renew the contract term and reaffirm that pre-Order No. 888 contracts cannot 

be altered upon their expiration. Powerex complains that the Commission did not address 

these proposals in Order No. 890 and that no commenting party put forward credible 

evidence to rebut the information Powerex presented the Commission in its NOPR 

comments. 

147. TDU Systems argue that transmission providers should be required to provide 

customers with access to modeling software used to calculate ATC values. TDU Systems 

state that Commission staff expressed concern at the Technical Conference held on 

October 12, 2006, in this docket that customers could find it difficult to sort through and 

use the large volume of data the Commission proposed to be posted by the transmission 

provider. TDU Systems argue that providing access to the modeling software used by the 

transmission provider to calculate ATC would resolve many of these concerns and better 

enable transmission customers to replicate and verify transmission provider ATC 

calculations, avoiding the potential for protracted litigation over the ATC results. TDU 

Systems contend that any proprietary or licensing concerns of the transmission provider 

or its vendors could be addressed through reasonable charges for use of the software 

and/or appropriate confidentiality agreements. 
Docket No. RM05-17-001, et al. - 75 -

Commission Determination

148. In Order No. 890, the Commission required transmission providers to make 

available, upon request, all data used to calculate ATC, TTC, CBM and TRM for any 

constrained posted path.62 We believe that this adequately addresses Constellation’s 

request for access to modeling data used by the transmission provider. Specifically, we 

expect transmission providers to make available, upon request and subject to appropriate 

confidentiality protections and CEII requirements, the following modeling data: (1) load 

flow base cases and generation dispatch methodology; (2) contingency, subsystem, 

monitoring, change files and accompanying auxiliary files; (3) transient and dynamic 

stability simulation data and reports on flowgates which are not thermally limited; (4) list 

of transactions used to update the base case for transmission service request study; 

(5) special protection systems and operating guides, and specific description as to how 

they are modeled; (6) model configuration settings; (7) dates and capacities of new and 

retiring generation; (8) new and retired generation included in the model for future years; 

(9) production cost models (including assumptions, settings, study results, input data, 

etc.), subject to reasonable and applicable generator confidentiality limitations; 

(10) searchable transmission maps, including PowerWorld or PSSE diagrams; 

(11) OASIS names to Common Names table and PTI bus numbers; and, (12) flowgate 

and interface limits including limit category (thermal, steady state or transient, voltage or 

angular). We decline, however, to require the transmission provider to post this 

 62 See id. at P 348. 
Docket No. RM05-17-001, et al. - 76 -

information on OASIS, as Constellation suggests. We conclude that making this 

information available on request provides sufficient transparency for customers without 

unduly burdening the transmission provider. 

149. With regard to the modeling support information sought by Constellation, we 

believe much of this information should already be stated in each transmission provider’s 

Attachment C. In Order No. 890, the Commission required each transmission provider to 

set forth in the Attachment C to its OATT the ATC calculation methodology used by the 

transmission provider.63 To the extent necessary, we clarify that the step-by-step 

modeling study methodology and criteria for adding or eliminating flowgates (permanent 

and temporary) is part of the ATC methodology that must be stated in the transmission 

provider’s Attachment C. We direct any transmission provider that has failed to include 

this information in its Attachment C to include that information as part of the compliance 

filing directed in section II.C. If the transmission provider has already satisfied this 

obligation in a previous compliance filing, it should refer to that filing instead. 

150. We deny as premature Constellation’s request to require OASIS postings of 

additional model benchmarking and forecasting data/TSR study audit data. Such 

information would be utilized in the process of updating and benchmarking models to 

actual events, which is the subject of ongoing efforts to modify relevant reliability 

standards from the MOD and facilities design, connections and maintenance (FAC) 

groups. 

 63 See id. at P 323. 
Docket No. RM05-17-001, et al. - 77 -

151. We decline to impose additional posting requirements regarding ETC uses, as 

requested by EPSA and Powerex. In Order No. 890, the Commission required 

transmission providers to make available all data used to calculate ATC for constrained 

paths and any system planning studies or specific network impact studies performed for 

customers.64 This would include information regarding ETC uses, including 

grandfathered agreements, that affect ATC calculations or study results. EPSA and 

Powerex fail to demonstrate that it is necessary to require the posting of additional 

information regarding ETC uses to verify the accuracy of the transmission provider’s 

ATC calculations. We note in response to Powerex that, if any new service taken upon 

expiration of a pre-Order No. 888 contract, the terms and conditions of the transmission 

provider’s OATT would apply.65

152. We deny TDU Systems’ request to require transmission providers to grant 

customers access to proprietary modeling software used to calculate ATC values. The 

Commission believes at this time that the requirements of Order No. 890 are sufficient to 

achieve the Commission’s transparency goals without further requiring the disclosure of 

proprietary software. 

 64 See id. at P 348. 

65 See Order No. 888 at 31,655. 
Docket No. RM05-17-001, et al. - 78 -

B. Coordinated, Open, and Transparent Planning

1. The Need for Reform

153. In Order No. 890, the Commission required transmission providers to participate 

in a coordinated, open, and transparent planning process on both a local and regional 

level. Transmission providers, including RTOs and ISOs, were directed to submit a 

compliance filing describing their proposals for a coordinated and regional planning 

process that comply with the planning principles and other requirements of Order No. 

890. The transmission planning process must be documented as an attachment to the 

transmission provider’s OATT. 

154. The Commission determined that planning-related reforms were necessary in 

order to limit opportunities for undue discrimination and to ensure that comparable 

transmission service is provided by all public utility transmission providers. The 

Commission stated that it did not intend to reopen prior approvals regarding planning 

processes adopted by RTOs and ISOs and, instead, sought to ensure that such planning 

processes are consistent with or superior to the requirements of Order No. 890. In order 

for an RTO’s or ISO’s planning process to be open and transparent, transmission 

customers and stakeholders must be able to participate in each underlying transmission 

owner’s planning process. The Commission therefore directed RTOs and ISOs to 

indicate in their compliance filings how participating transmission owners within their 

footprint will comply with the planning requirements of Order No. 890. 

155. The Commission also noted that the planning obligations imposed in Order No. 

890 did not address or dictate which investments identified in a transmission plan should 
Docket No. RM05-17-001, et al. - 79 -

be undertaken by transmission providers. Through the principles adopted by the 

Commission, a process was established through which transmission providers will 

coordinate with customers, neighboring transmission providers, affected state 

commissions, and other stakeholders in order to ensure that transmission plans are not 

developed in an unduly discriminatory manner. 

 Requests for Rehearing and Clarification

156. E.ON U.S challenges the Commission’s authority to adopt transmission planning 

rules beyond the implementation of service reservations or requests by customers. E.ON 

U.S. argues that the Commission’s reliance on new section 217(b)(4) of the FPA is 

misplaced because that provision does not enlarge the Commission’s authority and, in 

any event, Order No. 890 goes beyond assuring that LSEs have adequate transmission 

service. E.ON U.S. contends that characterizing transmission planning as a practice 

affecting rates would require an expansion of the Commission’s jurisdiction over the 

underlying rate, which it argues does not exist. 

157. Southern states that it supports the bulk of the coordinated planning provisions of 

Order No. 890, but nonetheless argues that reform is not needed to ensure that 

transmission planning is performed on a non-discriminatory basis. Southern states that it 

has invested billions of dollars in transmission over the last decade and expects to 

continue the trend of considerable investment through the foreseeable future. Southern 

also contends that it and other vertically-integrated utilities have obligations to procure 

generation through nondiscriminatory requests for proposals and that contracts awarded 

to any non-affiliated generator are already incorporated into the planning process as 
Docket No. RM05-17-001, et al. - 80 -

designated resources. Southern therefore contends that it does not have a disincentive to 

impede the ability of lower cost generation to access its control area. Southern suggests 

that any failure to upgrade interfaces is due to the lack of long-term firm service 

commitments to justify the upgrade, not a desire to keep lower-cost power from accessing 

the transmission provider’s control area. 

158. NYISO challenges the Commission’s reform of previously-approved RTO and 

ISO planning processes, arguing that the Commission cannot require changes to the 

NYISO planning process without first making a finding that it is no longer just and 

reasonable. NYISO contends that no such finding was made in Order No. 890, nor did 

the Commission identify discrimination in areas with centralized markets, such as 

NYISO. 

159. NRECA, Old Dominion, and TDU Systems ask the Commission to clarify that 

those RTOs and ISOs and other public utility transmission providers able to demonstrate 

that their planning processes are consistent with or superior to the requirements of Order 

No. 890 must nevertheless still file their planning process as part of their OATTs. These 

petitioners contend that requiring an RTO or an ISO to include the details of its planning 

process in its OATT, rather than its operating agreements, business manuals or website 

postings, will enable the Commission to monitor compliance with the reformed planning 

principles of Order No. 890 and provide needed transparency for customers. Entergy 

requests clarification that a transmission provider that has transferred authority over 

planning activities to an independent transmission coordinator may make the same 
Docket No. RM05-17-001, et al. - 81 -

compliance filings as an RTO/ISO, demonstrating that its existing planning process is 

consistent with or superior to the Order No. 890 requirements.

160. Old Dominion asks the Commission to clarify that the list of requirements in 

paragraph 602 of Order No. 890 (regarding the level of detail to be included in the 

OATT) is not exclusive and that, instead, every transmission provider must include the 

entirety of its planning process in its Attachment K with sufficient detail for stakeholders 

to understand that process. TDU Systems seek further clarification that transmission 

providers that have not turned over operational control of their facilities to an RTO or 

ISO must comply with the Attachment K filing obligations even if their facilities are 

governed by non-OATT arrangements, such as facilities agreements.

161. Several petitioners ask the Commission to clarify whether individual transmissionowning members within an RTO/ISO must comply with the planning-related posting and 

filing requirements of Order No. 890.66 New York Transmission Owners argue that, 

where there is an existing compliant regional planning process conducted by an RTO or 

ISO, participation in the planning process by a transmission owner is sufficient to satisfy 

the requirements of Order No. 890. Old Dominion and TDU Systems, however, seek 

confirmation that each of the nine planning principles adopted by the Commission apply 

equally to transmission owners that are members of an RTO, otherwise the RTO’s 

planning process will be insufficient to satisfy the requirements of Order No. 890. TDU 

 66 See, e.g., EEI, National Grid, New York Transmission Owners, Old Dominion, 

and TDU Systems. 
Docket No. RM05-17-001, et al. - 82 -

Systems argue that RTO and ISO tariff filings must provide detail on how the RTO will 

ensure transmission owner compliance with planning requirements and that reliance on 

statements of commitment to comply would be insufficient. Old Dominion contends that 

all filing and posting obligations should rest with the RTO or ISO and not their 

transmission-owning members. EEI suggests that the processes for incorporating the 

planning processes of transmission owning members of RTOs and ISOs should be 

addressed by each RTO and ISO. 

162. National Grid objects to any obligation to allow stakeholders an opportunity to 

preview the internal planning deliberations of transmission-owning RTO/ISO members 

prior to presentation of plans to the RTO or ISO. National Grid argues that this would 

give special interest stakeholders two opportunities to oppose specific projects, once at 

the local level without the full participation of the region and again at the regional level, 

and undermine the ability of the regional process to resolve conflicts between competing 

proposals. National Grid contends that it would be unfair to require transmission owners 

to open up their internal deliberations in advance of the regional planning process while 

allowing other stakeholders to deliberate in private their own strategies for the regional 

planning process. National Grid asks the Commission to clarify that the regional 

planning process is the appropriate forum in which stakeholders can examine each other’s 

upgrade proposals. National Grid argues that the adoption of separate local planning 

processes is not necessary to remedy undue discrimination and is unnecessary given that 

stakeholders in the ISO-NE regional planning process have an opportunity to comment 
Docket No. RM05-17-001, et al. - 83 -

on all aspects of the transmission plan, even those developed by the underlying 

transmission owners. 

163. Several petitioners challenge the Commission’s decision in Order No. 890 not to 

mandate the construction of facilities identified in a transmission plan. TAPS argues that 

the Commission’s finding that discrimination exists in expansion decisions compels 

obligating transmission providers to build needed facilities to accommodate uses 

identified in the planning process or explain why they cannot do so. TAPS contends that, 

under Order No. 890, a transmission provider can choose to build only the planned 

upgrades that benefit its native load, leaving a weak and uneven grid that prevents 

embedded TDUs from accessing economic alternatives. 

164. TAPS asks that the following measures be adopted to protect the interest of 

customers potentially harmed by failing to obligate the transmission provider to construct 

facilities identified in the transmission plan. First, TAPS suggests that transmission 

providers be required to accept any request for transmission to a network customer load, 

if necessary by redispatch shared on a load-ratio basis, if the request would have been 

accepted if the transmission provider’s own load had been designated the sink. Second, 

TAPS asks the Commission to require transmission providers to accept a network 

customer’s timely designated network resource so long as the designation is consistent 

with the regional transmission plan and the long-term projections and planning 

information provided by the customer pursuant to OATT § 31.6 and in the planning 

process, supporting the network resource designation through redispatch if necessary, 

with costs shared on a load-ratio basis. Third, TAPS suggests that transmission providers 
Docket No. RM05-17-001, et al. - 84 -

be required to offer embedded cost sales to transmission-dependent utilities if the 

provider’s failure to plan and construct on a comparable basis has left those embedded 

utilities trapped without reasonable access to competitive alternatives. Finally, TAPS 

asks the Commission to make clear that its “toolbox” to address egregious failures to plan 

and construct a robust grid that meets the needs of network customers includes the 

exercise of jurisdiction over the transmission component of bundled retail sales of a 

particular utility to remedy undue discrimination.67

165. TAPS argues that these measures would provide transmission providers with the 

right financial incentives to construct facilities identified in the transmission plan. If the 

transmission provider fails to build and there is insufficient capacity to accommodate 

planned uses, TAPS argues it is appropriate for the transmission provider to share the 

cost of providing alternative service. TAPS argues that this would also mitigate the 

Commission’s concern that imposing an obligation to build would conflict with the need 

for transmission plans to change over time.

166. TAPS also suggests that the Commission monitor the transmission provider’s 

actions by requiring any denial of service to a network customer be reported to the 

Commission so that the transmission provider can demonstrate to enforcement staff that 

the transmission provider has adequately planned for its customers and made diligent 

efforts to build planned upgrades. TAPS also argues that transmission providers should 

be required to demonstrate that they are making good faith efforts to obtain any necessary 

 67 Citing New York v. FERC, 535 U.S. 1 (2002). 
Docket No. RM05-17-001, et al. - 85 -

state and local siting approvals and to acquire any property rights necessary to construct 

planned facilities in order to show that they are not selecting projects for construction that 

favor their own uses over the uses of their network customers. 

167. TDU Systems agree that better planning will not remedy or mitigate undue 

discrimination without an enforceable obligation to actually construct upgrades needed to 

ensure reliable and economic service to LSEs. TDU Systems argue that an obligation to 

build would be consistent with other reforms adopted in Order No. 890, such as 

extending the minimum term of contracts eligible for rollover rights and eliminating the 

price cap on reassignments of capacity, by ensuring that adequate capacity exists to 

accommodate transmission service requests. They contend that the failure to mandate 

expansion of the grid is particularly egregious in situations when zero ATC values are 

posted on a recurring or lengthy basis, which they argue should trigger a rebuttable 

presumption that congestion exists on the transmission system and that upgrades are 

needed. TDU Systems contend that failing to require transmission providers to expand 

their systems in these and other situations is inconsistent with the requirement of section 

217(b)(4) of the FPA for the Commission to exercise its authority to facilitate the 

planning and expansion of transmission facilities to meet the reasonable needs of LSEs. 

168. TDU Systems suggest that the Commission strengthen and aggressively enforce 

the existing construction obligations in the pro forma OATT and subject transmission 

providers that fail to implement a transmission plan in good faith to sanctions. TDU 

Systems argue that section 28.2 of the pro forma OATT should be amended to require a 

transmission provider to do more than endeavor to construct new facilities needed to 
Docket No. RM05-17-001, et al. - 86 -

meet network customer load or, in the alternative, the Commission should indicate that it 

will aggressively enforce the existing obligation to build. They request that the 

Commission adopt a clear policy of sanctions for cases in which a transmission provider 

is found to have failed to proceed in good faith and with due diligence in implementing 

the planning process. TDU Systems ask the Commission to clarify in particular that it 

will consider revocation of market-based rate authority for bad faith in implementing the 

transmission planning and expansion requirements under Order No. 890. 

169. NRECA also urges the Commission to reiterate and enforce the existing 

obligations to build in order to meet its service obligations to network and long-term 

point-to-point customers under the pro forma OATT.68 NRECA argues that the 

obligation to expand capacity should be viewed as part and parcel of the transmission 

provider’s obligation to plan for these customers and that statements to the contrary in 

Order No. 890 should be clarified. NRECA argues that leaving the transmission provider 

with the discretion not to build facilities identified in the transmission plan would allow it 

to discriminate in favor of its native load customers to the detriment of network and longterm point-to-point customers.

170. Washington IOUs request clarification that the planning requirements of Order 

No. 890 do not supersede the planning and coordination activities undertaken by a 

transmission provider under its network operating agreements. Washington IOUs state 

that transmission providers providing network service currently engage in local planning 

 68 Citing pro forma OATT sections 13.5, 15.4 and 28.2. 
Docket No. RM05-17-001, et al. - 87 -

and coordination activities with network customers to ensure their needs are met and that 

such activities should not be superseded by the planning-related reforms of Order No. 

890. 

Commission Determination

171. The Commission affirms the decision in Order No. 890 to amend the pro forma

OATT to require coordinated, open and transparent transmission planning on both a local 

and regional level. Although the Commission encouraged utilities to engage in joint 

planning in Order No. 888-A, it placed no affirmative obligation on transmission 

providers to coordinate with their customers in transmission planning or otherwise 

publish the criteria, assumptions, or data underlying their transmission plans, nor were 

transmission providers required to coordinate planning activities with other transmission 

providers in their region. This lack of clear criteria regarding planning obligations has 

created opportunities for undue discrimination by transmission monopolists with an 

incentive to deny transmission or offer transmission on an inferior basis. 

172. Petitioners generally do not challenge the Commission’s conclusion that the lack 

of coordination, openness, and transparency results in opportunities for undue 

discrimination in transmission planning and, instead, raise more narrow arguments 

regarding particular aspects of the planning reforms. E.ON U.S. argues that the 

Commission must limit the scope of the planning requirements to implementation of 

service requests. We disagree. The Commission has a statutory obligation under 

sections 205 and 206 of the FPA to ensure that each public utility’s rates, charges, 

classifications, and services are just and reasonable and not unduly discriminatory. The 
Docket No. RM05-17-001, et al. - 88 -

Commission has exercised jurisdiction over planning-related proposals submitted by 

individual transmission providers in the past, rejecting arguments regarding a lack of 

jurisdiction.69 Transmission planning activities are within our jurisdiction and, therefore, 

we have a duty under FPA section 206 to remedy undue discrimination in this area and a 

further obligation under FPA section 217 to act in a way that facilitates the planning and 

expansion of facilities to meet the reasonable needs of LSEs.

173. The fact that transmission providers, such as Southern, have undertaken some 

transmission investment in recent years does not mean that planning reform is not 

needed. Southern does not challenge the fundamental conclusion that it is in the 

economic self-interest of transmission monopolists to discriminate in the provision of 

service and, in turn, in planning-related activities. The ability of generators to participate 

in requests for proposals for generation service does not adequately respond to the need 

for a coordinated, open, and transparent transmission planning process that considers the 

needs of all customers as well as the transmission provider itself. The planning process 

adopted in Order No. 890 is designed to enhance the ability of all customers to make 

long-term firm service commitments by allowing them to participate in the transmission 

provider’s planning activities. 

174. The Commission also based its planning-related reforms on the need to ensure 

comparable transmission service by all transmission providers, including RTOs and ISOs. 

 69 See New York Independent System Operator, Inc., 109 FERC ¶ 61,372 at P 18 

(2004); Southwest Power Pool, Inc., 109 FERC ¶ 61,010 at P 78 (2004). 
Docket No. RM05-17-001, et al. - 89 -

We therefore disagree with NYISO that the Commission failed to justify application of 

the Attachment K filing obligations to RTOs and ISOs. The Commission was not 

required to find each and every tariff unjust and unreasonable to adopt this rulemaking, 

and, instead, had the discretion to adopt principles of generic applicability to govern all 

transmission tariffs. Indeed, we made clear, and reiterate here, that RTOs and ISOs can 

continue to rely on their existing planning processes if those processes meet the 

requirements of Order No. 890. As the Commission explained, it is not our intention to 

reopen prior approvals simply for the sake of doing so, but rather to ensure that those 

previously-approved planning processes fulfill the obligations imposed on all 

transmission providers in Order No. 890.70 

175. We therefore affirm the decision to require all transmission providers to comply 

with the planning-related reforms adopted in Order No. 890, including RTOs and ISOs. 

We agree with Old Dominion that the filing and posting requirements stated in Order No. 

890 apply only to the transmission provider, e.g., the RTO or ISO, and not the 

transmission-owning RTO/ISO members without an OATT.71 Each RTO and ISO may 

fulfill its obligations under Order No. 890 by delegating certain actions to, or otherwise 

 70 See Order No. 890 at P 437. 

71 As the Commission noted in Order No. 890, transmission owning members of 

an RTO or ISO that continue to have OATTs on file under which they provide service 

over jurisdictional facilities not under control of the RTO or ISO would continue to have 

filing obligations under Order No. 890, like any other transmission provider. See id. at 

P 440, n.247. This would apply equally to a transmission provider that has retained 

operational control of facilities governed by other non-OATT arrangements. 
Docket No. RM05-17-001, et al. - 90 -

relying on, their transmission-owning members, provided that the rights and 

responsibilities of all parties are clearly stated in the transmission provider’s OATT. In 

the end, however, it is each RTO’s and ISO’s responsibility to demonstrate compliance 

with each of the nine planning principles adopted in Order No. 890 since it is the entity 

with the Attachment K on file.

176. We clarify in response to National Grid that an RTO or ISO would not be able to 

satisfy the requirements of Order No. 890 if the plans developed by its transmissionowning members and relied upon by the RTO/ISO did not also satisfy those 

requirements. A fundamental assumption underlying National Grid’s argument is that 

issues addressed in a local planning proposal should be final prior to its introduction at 

the regional level. Yet such finality could exclude customers from the development of 

aspects of what eventually becomes the regional plan implemented by the RTO or ISO. 

As the Commission explained in Order No. 890, local planning issues may be critically 

important to some transmission customers, such as those embedded within the service 

areas of individual transmission owners.72 While we leave the mechanics of 

incorporating the planning processes of transmission owning members to each RTO and 

ISO, as EEI suggests, it would not be appropriate to entirely exclude such processes as 

proposed by National Grid.

177. To the extent necessary, we clarify in response to NRECA, Old Dominion and 

TDU Systems that every transmission provider, including RTOs and ISOs, must submit a 

 72 See id. at P 440. 
Docket No. RM05-17-001, et al. - 91 -

compliance filing stating its transmission planning process in an attachment to its OATT. 

This tariff language must satisfy all of the requirements of Order No. 890 with sufficient 

detail for stakeholders to understand the planning process implemented by the 

transmission provider. To the extent the transmission provider previously received 

Commission approval to delegate planning responsibilities to an independent 

transmission coordinator, the transmission provider may demonstrate in its compliance 

filing that its planning process is consistent with or superior to the Order No. 890 

planning requirements, similar to the RTO and ISO compliance filings. 

178. The Commission declines to expand the pro forma OATT to place additional 

obligations on the transmission provider to construct facilities identified in its 

transmission plan. As the Commission explained in Order No. 890, there may be reasons 

a transmission provider declines to undertake a particular project given the complexity of 

the transmission grid and changing conditions of supply and demand.73 Our focus is 

therefore on the process leading to the transmission plan and not the construction of 

specific facilities. This does not, as some petitioners argue, undermine the constructionrelated obligations that exist under sections 13.5, 15.4 and 28.2 of the pro forma OATT. 

The planning-related reforms adopted in Order No. 890 are intended to support, not 

replace, those requirements by establishing a process to govern all planning-related 

decisions.

 73 See id. at P 594. 
Docket No. RM05-17-001, et al. - 92 -

179. We therefore believe adequate protections are in place to ensure that transmission 

providers do not unduly discriminate in the selection of which facilities they choose to 

construct to the detriment of their customers. If a particular customer believes that its 

transmission provider has in fact not complied with its OATT obligations, the customer 

should bring the matter to the Commission’s attention, such as by filing a complaint. 

Indeed, the planning-related reforms adopted in Order No. 890 will facilitate tariff 

compliance by opening up the transmission provider’s decisional process, providing 

much needed transparency in the area of transmission planning.

180. We deny as unnecessary TAPS’ request to impose additional accountability 

mechanisms or require other demonstrations regarding a transmission provider’s 

construction decisions or to generically address the appropriateness of sanctions, 

including revocation of market-based rate authority, for non-compliance with tariff 

obligations. We will likewise deny requests to revise the construction-related obligations 

of the pro forma OATT. The Commission will remain actively involved in the review 

and implementation of the transmission planning processes required in Order No. 890, 

during and beyond the initial compliance phase, to ensure that the potential for undue 

discrimination in planning activities is adequately addressed. Further, we expect 

transmission customers to advise the Commission if transmission providers do not adhere 

to the terms of the tariff provisions we ultimately approve. In the absence of specific 

evidence that a transmission provider has failed to satisfy its tariff obligations, either 

under sections 13.5, 15.4 or 28.2 of the pro forma OATT or its Attachment K planning 

process, we believe it unnecessary to adopt the additional measures proposed by TAPS. 
Docket No. RM05-17-001, et al. - 93 -

In the case of tariff non-compliance, the Commission will consider these and any other 

remedies that may be appropriate on a case-by-case basis in the context of the specific 

facts presented. 

2. Planning Principles

181. The Commission identified nine planning principles in Order No. 890 that must be 

satisfied for a transmission provider’s planning process to be considered compliant with 

that order. These nine planning principles are: 

(1) Coordination – the process for consulting with transmission customers and 

neighboring transmission providers; 

(2) Openness – planning meetings must be open to all affected parties; 

(3) Transparency – access must be provided to the methodology, criteria, and 

processes used to develop transmission plans; 

(4) Information Exchange – the obligations of and methods for customers to 

submit data to transmission providers must be described; 

(5) Comparability – transmission plans must meet the specific service requests of 

transmission customers and otherwise treat similarly-situated customers (e.g., 

network and retail native load) comparably in transmission system planning; 

(6) Dispute Resolution – an alternative dispute resolution process to address both 

procedural and substantive planning issues must be included; 

(7) Regional Participation – there must be a process for coordinating with 

interconnected systems; 
Docket No. RM05-17-001, et al. - 94 -

(8) Economic Planning Studies – study procedures must be provided for economic 

upgrades to address congestion or the integration of new resources, both locally 

and regionally; and

(9) Cost Allocation – a process must be included for allocating costs of new 

facilities that do not fit under existing rate structures, such as regional projects. 

Petitioners have requested rehearing and clarification regarding certain of these 

principles, which we address in turn. 

a. Coordination 

182. In order to satisfy the coordination principle, transmission providers must provide 

stakeholders the opportunity to participate fully in the planning process. The purpose of 

the coordination requirement is to eliminate the potential for undue discrimination in 

planning by opening appropriate lines of communication between transmission providers, 

their transmission-providing neighbors, affected state authorities, customers, and other 

stakeholders. The planning process must provide for the timely and meaningful input and 

participation of customers regarding the development of transmission plans, allowing 

customers to participate in the early stages of development.

Requests for Rehearing and Clarification

183. EPSA and TDU Systems argue that, under Order No. 890, transmission providers 

inappropriately retain veto rights over the decision as to which upgrade projects to 

include in transmission plans. These petitioners acknowledge that the transmission 

provider has the ultimate obligation to comply with its tariff, but argue that those tariff 

obligations be fulfilled in a way that allows for full and equal participation of customers. 
Docket No. RM05-17-001, et al. - 95 -

EPSA argues that transmission providers should be obligated to consider consensus 

positions, to present to the Commission or its designee minority opinions that have been 

excluded, and to explain why consensus proposals that have been disregarded will not be 

converted into actual plans to expand or reduce constraints on the system. TDU Systems 

request that transmission providers be required to post on their websites a record of the 

transmission planning decisions that reflect the views and votes of all participants to that 

process. TDU Systems argue that this would enable the Commission to determine 

whether the plan reflects consensus among stakeholders and the needs of customers, as 

opposed to the unilateral determinations of the transmission providers. NRECA asks the 

Commission to clarify that LSEs in particular have the opportunity to be an integral and 

equal part of the regional planning process from the beginning of the process to its end, 

including implementation of the regional participation principle. 

184. NRECA argues that comparability requires that LSEs have equal weight in 

decision-making. Otherwise, NRECA contends that transmission providers will continue 

to have the opportunity and right to discriminate. NRECA expresses concern that 

transmission providers will be able to develop the basic criteria, assumptions, and data 

that underlie transmission plans on their own and merely present the results to customers 

after the fact. NRECA asks the Commission to clarify that public utility transmission 

providers may not arbitrarily, deliberately, or discriminatorily disregard the input of LSE 

customers at any stage in the development and drafting of the transmission plan and 

modify the pro forma Attachment K to reflect that LSEs will be an integral part of the 

planning process.
Docket No. RM05-17-001, et al. - 96 -

185. With regard to small LSE customers, NRECA asks the Commission to clarify that 

the new requirement that transmission providers develop and implement joint planning 

processes does not leave customers that lack the resources to fully participate in the 

planning process in a worse position than they were in under Order No. 888. NRECA 

states that, under Order No. 888, transmission providers were required to plan and expand 

their systems to meet the needs of all network customers and long-term point-to-point 

customers. NRECA contends that the new joint planning requirement could be read to 

allow transmission providers to refuse to consider these customers’ needs if they are 

unable to participate fully in the transmission planning process. NRECA suggests that 

participation in the planning process be an opportunity for load-serving customers, not an 

obligation, and that transmission providers be required to plan for those that are unable to 

fully participate. 

186. Constellation requests that the Commission clarify that it will closely monitor the 

planning process to ensure that reforms are implemented in a meaningful way and that 

customers have the ability to truly participate in the process. Williams requests that the 

planning-related requirements of Order No. 890 be augmented to require a written record 

of stakeholder input, in order to guarantee informed consideration and debate of nontransmission provider proposals. 

187. EEI seeks clarification that transmission providers may adopt restrictions on the 

disclosure of CEII in the context of transmission planning. EEI argues that login 

requirements and nondisclosure agreements may not provide sufficient protection for 

CEII. EEI suggests that transmission providers be allowed to adopt the Critical 
Docket No. RM05-17-001, et al. - 97 -

Infrastructure Protection (CIP) reliability standards for the disclosure of CEII that the 

Commission adopts in Docket No. RM06-22-000, Mandatory Reliability Standards for 

Critical Infrastructure Protection. 

Commission Determination 

188. The Commission affirms the decision in Order No. 890 not to require the 

development of transmission plans on a co-equal basis with customers. Transmission 

planning is the tariff obligation of the transmission provider, and the pro forma OATT 

planning process adopted in Order No. 890 is the means to see that it is carried out in a 

coordinated, open, and transparent manner. It would not be appropriate to allow 

customers and others that do not bear the responsibility for tariff compliance to have coequal control over the planning process. We reiterate, however, that the planning process 

must provide for the timely and meaningful input and participation of all interested 

customers and other stakeholders in the development of transmission plans. Customers 

and other stakeholders therefore must have the opportunity to participate at the early 

stages of the development of the transmission plan, rather than merely given an 

opportunity to comment on transmission plans that were developed in the first instance 

without their input. 

189. We disagree that the additional processes proposed by EPSA, TDU Systems, and 

Williams are necessary at this time to ensure that transmission providers do not unduly 

discriminate in the performance of their planning responsibilities. Customers and other 

stakeholders have been given a meaningful opportunity to participate in the planning 

process and to voice their concerns, not a formal “vote” on the transmission plan. While 
Docket No. RM05-17-001, et al. - 98 -

we would not consider it reasonable for the transmission provider to act in an arbitrary 

fashion by simply ignoring the comments and concerns of interested parties, we do not 

believe it appropriate at this time to adopt additional procedural mechanisms to measure 

or track the views of those participants in the planning process. Should disputes arise, 

they should first be addressed through the dispute resolution process set forth in the 

transmission provider’s Attachment K and then, if necessary, to the Commission’s 

attention through a complaint or other appropriate procedural mechanism. 

190. With regard to participation by small LSEs in planning activities, we reiterate that 

the planning process adopted in Order No. 890 is intended to supplement, not replace, the 

transmission provider’s obligations under section 28.2 of the pro forma OATT to plan for 

the transmission needs of its network customers on a comparable basis and in accordance 

with Good Utility Practice, as well as the obligation to construct new facilities pursuant 

to sections 13.5 and 15.4 of the pro forma OATT to meet the service requests of its longterm point-to-point customers. Transmission providers are therefore required to craft a 

planning process that allows for a reasonable and meaningful opportunity for those that 

are interested and able to meet and otherwise interact with the transmission provider.74 

Notwithstanding a smaller LSE’s inability to participate in the additional processes 

implemented in compliance with Order No. 890, the transmission provider still must 

fulfill its network service obligation to that customer. 

 74 See Order No. 890 at P 453. 
Docket No. RM05-17-001, et al. - 99 -

191. In response to EEI, we clarify that, in addition to login requirements and 

nondisclosure agreements, transmission providers may adopt further restrictions on the 

distribution of CEII consistent with any CIP reliability standards that the Commission 

may adopt in Docket No. RM06-22-000 

b. Openness

192. In order to satisfy the openness principle, transmission planning meetings must be 

open to all affected parties including, but not limited to, all transmission and 

interconnection customers, state commissions and other stakeholders. The Commission 

recognized in Order No. 890 that it may be appropriate in certain circumstances, such as 

a particular meeting of a subregional group, to limit participation to a relevant subset of 

these entities. The Commission emphasized, however, that the overall development of 

the plan must remain open. 

Requests for Rehearing and Clarification

193. TDU Systems argue that any condition under which a transmission planning 

meeting could be limited so as to exclude certain customers or stakeholders must be 

explicitly set forth in the transmission provider’s Attachment K. Otherwise, TDU 

Systems contend the transmission provider will retain undue discretion over who is 

allowed to participate in meetings. 

Commission Determination

194. The Commission agrees with TDU Systems that the circumstances under which 

participation in a planning meeting is limited should be clearly described in the 
Docket No. RM05-17-001, et al. - 100 -

transmission provider’s Attachment K planning process. All affected parties must be 

able to understand how, and when, they are able to participate in planning activities. 

c. Transparency

195. In order to satisfy the transparency principle, transmission providers must disclose 

to all customers and other stakeholders the basic criteria, assumptions, and data that 

underlie their transmission system plans. The Commission concluded that this 

information should enable customers, other stakeholders, or an independent third party to 

replicate the results of planning studies and thereby reduce the incidence of after-the-fact 

disputes regarding whether planning has been conducted in an unduly discriminatory 

fashion. Among other things, the Commission required transmission providers to make 

available information regarding the status of upgrades identified in their transmission 

plans in addition to the underlying plans and related studies. 

Requests for Rehearing and Clarification

196. TDU Systems ask the Commission to clarify that transmission providers, and 

transmission-owning members of an RTO or ISO, must provide customers and other 

stakeholders with base case and change case data. TDU Systems contend that this would 

be consistent with the Commission’s goal of allowing stakeholders to replicate the results 

of planning studies and, in their view, would virtually eliminate disputes regarding 

whether planning has been conducted in an unduly discriminatory fashion. 

197. TAPS questions whether the Standards of Conduct would trigger the full 

functional separation requirement for a non-public utility transmission provider 

participating in the planning process. TAPS contends that both transmission and 
Docket No. RM05-17-001, et al. - 101 -

generation functions of a non-public utility transmission provider could participate in 

planning activities, consistent with the Standards of Conduct, so long as all information 

used in transmission planning is made available to all participants. If the Commission 

disagrees, TAPS asks that new mechanisms be adopted to assure information is not 

abused, independent from the Standards of Conduct and existing Standards of Conduct 

waivers that do not inhibit the participation of non-public utility transmission providers in 

the planning process. TAPS suggests that any entity be allowed to participate in the 

regional planning process if it establishes procedures defining which 

employees/consultants may receive confidential transmission and planning information 

and prohibiting such employees/consultants from sharing that information with the 

entity’s wholesale merchant personnel. 

198. Old Dominion requests that the Commission adopt performance metrics governing 

transmission planning in addition to reports regarding the status of upgrades. Old 

Dominion suggests that the Commission specifically require transmission providers to 

report on the progress and construction of all upgrades and facilities in the transmission 

plan. 

Commission Determination

199. In Order No. 890, the Commission required transmission providers to disclose to 

all customers and other stakeholders the basic criteria, assumptions, and data that underlie 

their transmission system plans.75 To the extent necessary, we clarify in response to TDU 

 75 See id. at P 471. 
Docket No. RM05-17-001, et al. - 102 -

Systems that this includes disclosure of transmission base case and change case data used 

by the transmission provider. These are basic assumptions necessary to adequately 

understand the results reached in a transmission plan. 

200. With regard to management of non-public information by non-public utility 

transmission providers, we reiterate that the reciprocity obligation requires non-public 

utility transmission providers to abide by the Standards of Conduct or obtain waiver of 

them.76 Although we recognize that compliance with the Standards of Conduct can 

impose costs on small entities, an open planning process cannot be fully successful if 

certain entities (whether jurisdictional or nonjurisdictional) can use planning-related 

information to obtain an undue advantage. The Commission therefore explained in Order 

No. 890 that it may be necessary to revisit waivers of the Standards of Conduct granted to 

certain non-public utility transmission providers in the past.77 The Commission declined 

to alter such waivers on a generic basis in Order No. 890 and we affirm that decision 

here.

201. As TAPS notes, many of the concerns regarding management of non-public 

information shared in the planning process can be alleviated by simultaneous disclosure 

of that information to all participants. Moreover, the Standards of Conduct govern the 

relationship and exchange of information between transmission providers and their 

marketing or energy affiliates. Entities that do not own, operate or control transmission 

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

77 See Order No. 890 at P 474. 
Docket No. RM05-17-001, et al. - 103 -

facilities, and who are not affiliated with transmission providers, are not subject to the 

Standards of Conduct. We believe establishment of new mechanisms to manage the 

sharing of non-public planning information by transmission providers subject to the 

Standards of Conduct would be premature and more appropriately addressed in any 

proceeding in which the revocation of a Standards of Conduct waiver is considered. 

202. We also decline to adopt additional performance metrics governing transmission 

planning. The Commission required in Order No. 890 for transmission providers to make 

available information regarding the status of upgrades identified in their transmission 

plans.78 Customers and other stakeholders that are interested in the implementation of the 

transmission plan will be able to monitor this information to gather information regarding 

the progress and construction of upgrades and facilities. The Commission does not 

believe further reporting requirements are necessary at this time to keep interested parties 

informed regarding the status of upgrades identified in a transmission plan.

d. Information Exchange

203. In order to satisfy the information exchange principle, transmission providers must 

develop guidelines and a schedule for the submittal of information in consultation with 

their network and point-to-point customers. The Commission stressed that information 

collected by transmission providers to provide transmission service to their native load 

customers must be transparent and equivalent information must be provided by 

transmission customers to ensure effective planning and comparability. Point-to-point 

 78 See id. at P 472. 
Docket No. RM05-17-001, et al. - 104 -

customers were also required to submit any projections they have of a need for service 

over the planning horizon and at what receipt and delivery points. 

 Requests for Rehearing and Clarification

204. E.ON U.S. requests that the Commission clarify that all entities seeking 

comparable treatment for transmission planning purposes, including any non-public 

utilities, must share their cost information with the transmission provider, as needed for 

planning purposes. E.ON U.S. contends that it must have access to information regarding 

all of its customers’ dispatch and transmission costs in order to implement joint planning 

as envisioned by Order No. 890. E.ON U.S. acknowledges that this information would 

need to be treated as competitively sensitive and shielded from the transmission 

provider’s merchant function employees. 

205. Duke seeks clarification that projections of a point-to-point customer’s anticipated 

needs do not have to be included in the models serving as the predicate of the 

transmission plan. Duke agrees that, while projected uses may be helpful in 

understanding the scope of the potential need for future upgrades, only reservations 

impose an obligation on the transmission provider. 

Commission Determination

206. The Commission clarifies in response to E.ON U.S. that, within the context of 

transmission planning, customers should only be required to provide cost information for 

transmission and generation facilities as necessary for the transmission provider to 

perform economic planning studies requested by the customer. If stakeholders request 

that a particular congested area be studied, they must supply relevant data within their 
Docket No. RM05-17-001, et al. - 105 -

possession to enable the transmission provider to calculate the level of congestion costs 

that is occurring in the near future.79 This may necessarily involve customers providing 

their cost information. As E.ON U.S. notes, transmission providers must maintain the 

confidentiality of this information, protecting it from distribution to employees of the 

merchant function and its affiliates. Transmission providers must clearly define in their 

Attachment K the information sharing obligations placed on customers in the context of 

economic planning. 

207. We clarify in response to Duke that good faith projections of anticipated point-topoint uses of the transmission system are intended only to give the transmission provider 

additional data to consider in its planning activities. The Commission did not intend to 

suggest in Order No. 890 that such projections be treated as a proxy for actual 

reservations. Even though they are not the equivalent of reserved uses of the system, 

such projections could, for example, provide planners with likely scenarios for new 

investment. 

e. Comparability

208. In order to satisfy the comparability principle, transmission providers must 

develop, after considering the data and comments supplied by customers and other 

stakeholders, a transmission system plan that (1) meets the specific service requests of its 

transmission customers and (2) otherwise treats similarly-situated customers (e.g., 

 79 See id. at P 550. The Commission also required the transmission provider’s 

merchant function to provide any information necessary for economic planning studies 

(e.g., redispatch cost information). 
Docket No. RM05-17-001, et al. - 106 -

network and retail native load) comparably in transmission system planning. The 

Commission also required that customer demand resources be considered on a 

comparable basis to the service provided by comparable generation resources where 

appropriate. 

Requests for Rehearing and Clarification

209. E.ON U.S. argues that the comparability principle poses a dilemma for verticallyintegrated utilities in that the utility must engage in least cost planning at the state level, 

but is required to engage in comparable planning at the federal level. E.ON U.S. 

questions whether comparability requires the transmission provider to include all 

customer-identified projects in its plan or whether the transmission provider must merely 

consult with customers regarding their projects. E.ON U.S. also objects to treating a nonpublic utility customer comparably to its own native load in instances when the nonpublic utility customer fails to do the same in its own transmission planning activities. 

E.ON U.S. requests that the Commission clarify that public utilities are not required to 

include non-public utilities in transmission planning to the extent a non-public utility has 

not adopted the transmission planning principles of the pro forma OATT. 

210. REPIO argue that planning processes must be clear to ensure that transmission 

providers fairly consider and implement the best alternatives among transmission, 

generation, and demand response options. To that end, REPIO ask the Commission to 

make explicit the requirement that all resource options be given technology neutral 

treatment.
Docket No. RM05-17-001, et al. - 107 -

211. Areva, however, argues that transmission providers must be required to do more 

than simply include demand resources in the planning process, arguing that the 

Commission failed to adequately encourage the use of alternative technologies as 

required by section 1223 of EPAct 2005. Areva contends that the Commission erred in 

failing to provide new opportunities for advanced technologies in the energy markets, 

particularly demand response resources. Areva argues it is inadequate to merely allow 

participation of comparable demand-side resources and, instead, the Commission must 

take the steps necessary to promote integration of advanced technologies in the planning 

process, including the assessment of penalties for failure to include such technologies in 

transmission plans and, ultimately, on the transmission grid. If the Commission declines 

to do so, Areva contends that the Commission at a minimum should require transmission 

providers to report their consideration of advanced technologies in their planning process, 

highlight uses of such technologies in their resulting transmission plan, or report to the 

Commission why such technologies were excluded from the resulting transmission plan. 

212. TDU Systems, however, ask the Commission to confirm that demand resources 

can only substitute for truly comparable generation resources in the planning process. 

TDU Systems state that demand resources are, for example, non-dispatchable and can be 

reasonably substituted only for equivalent non-dispatchable blocks of energy. TDU 

Systems ask the Commission to establish criteria for determining whether demand 

resources are comparable to generation resources for purposes of consideration in the 

transmission plan or direct transmission providers to develop such criteria in their 

Attachment K proposals. 
Docket No. RM05-17-001, et al. - 108 -

Commission Determination 

213. Comparability requires that the interests of transmission providers and their 

similarly-situated customers be treated on a comparable basis in the transmission 

planning process.80 We do not believe that this creates a conflict with least cost planning 

at the state level. Comparability simply requires that a transmission provider engage in 

comparable planning for its similarly-situated customers. The transmission provider 

retains discretion as to which solutions to pursue. Transmission providers are therefore 

not required to include all customer-identified projects in its plan, so long as similarlysituated customers are given comparable consideration.

214. With regard to non-public utility transmission providers, we reiterate our 

expectation of participation in the planning processes established pursuant to Order No. 

890 consistent with their reciprocity obligations.81 Reciprocity dictates that non-public 

utility transmission providers that take advantage of open access due to improved 

planning should be subject to the same requirements as jurisdictional providers. A nonpublic utility transmission provider with reciprocity obligations that declines to adopt a 

planning process that complies with Order No. 890 therefore may not be considered to be 

providing reciprocal transmission service and may be at risk of being denied open access 

transmission services by a public utility transmission provider. We will consider on a 

case-by-case basis how a transmission provider should treat for planning purposes a non-

 80 See id. at P 494. 

81 See id. at P 441. 
Docket No. RM05-17-001, et al. - 109 -

public utility transmission provider that fails to implement a planning process that fulfills 

the requirements of Order No. 890.82 

215. We disagree with Areva that the transmission planning process required in Order 

No. 890 is inconsistent with section 1223 of EPAct 2005.83 The Commission made clear 

in Order No. 890 that advanced technologies and demand-side resources must be treated 

comparably where appropriate in the transmission planning process and, thus, the 

transmission provider’s consideration of solutions should be technology neutral. We 

believe that the reforms adopted in Order No. 890 are sufficient to ensure comparable 

consideration of such technologies in transmission planning and, therefore, we decline to 

impose the type of special penalties proposed by Areva.

216. We disagree with TDU Systems that comparability requires that generation 

resources and demand resources be subject to the same operational parameters in every 

circumstance. Treating similarly-situated resources on a comparable basis does not 

necessarily mean that the resources are treated the same. As part of its Attachment K 

 82 As the Commission noted in Order No. 890, the Commission may exercise its 

authority under section 211A on a case-by-case basis if we find on the appropriate record 

that non-public utility transmission providers are not participating in the planning 

processes required therein. See id. at P 441. 

83 We note that, in addition to the reforms adopted in Order No. 890, the 

Commission is taking steps in other proceedings to encourage the deployment of 

advanced technologies as required by section 1223 of EPAct 2005. See, e.g., Promoting 

Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43294 (July 31, 

2006), FERC Stats & Regs. ¶ 31,222 at P 302 (2006), order on reh’g, Order No. 679-A, 

72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. ¶ 31,236 (2007), order on reh’g, Order 

No. 679-B, 119 FERC ¶ 61,062 (2007). 
Docket No. RM05-17-001, et al. - 110 -

planning process, each transmission provider is required to identify how it will treat 

resources on a comparable basis and, therefore, should identify how it will determine 

comparability for purposes of transmission planning.

f. Dispute Resolution

217. In order to satisfy the dispute resolution principle, transmission providers must 

develop a dispute resolution process to manage disputes that arise from the Attachment K 

planning process. The Commission stated that the dispute resolution process must 

address both procedural and substantive planning issues, as the purpose for including a 

dispute resolution process is to provide a means for parties to resolve all disputes related 

to the planning process before turning to the Commission. 

 Requests for Rehearing and Clarification

218. TDU Systems ask the Commission to clarify that transmission providers must 

develop a dispute resolution process in collaboration with transmission customers and 

other stakeholders. TDU Systems argue that this clarification is necessary to assure that 

“the shape of the table” for dispute resolution is not fashioned to favor one side.

219. Duke asks the Commission to clarify whether alternative dispute resolution (ADR) 

will become a vehicle to challenge the transmission plan ultimately adopted by the 

transmission provider. Duke questions any intent by the Commission to exercise 

authority to approve or disapprove a transmission plan. Duke argues that ADR should 

not be used to substantively second guess a vertically-integrated transmission provider’s 

plan. If ADR is intended to address substantive planning issues, Duke asks the 

Commission to clearly delineate the scope of those issues. Duke also asks the 
Docket No. RM05-17-001, et al. - 111 -

Commission to state the basis for any determination that ADR could be used to require 

changes to a transmission plan that would have the effect of fashioning binding 

obligations to build or not to build any particular facility in contravention of the 

transmission plan.

Commission Determination

220. As with any aspect of the transmission provider’s Attachment K compliance filing, 

the Commission encourages stakeholder involvement in the development of an 

appropriate dispute resolution process to govern planning-related disputes. The 

Commission will carefully review each compliance filing to ensure that the proposed 

planning process is consistent with the principles and other requirements of Order No. 

890. Any stakeholder that has concerns regarding the dispute resolution mechanism 

proposed by a transmission provider, or any other aspect of the compliance filing, may 

bring them to the Commission’s attention on review of the proposal. 

221. We disagree with Duke that the scope of this dispute resolution mechanism is 

limited to procedural issues. As the Commission explained in Order No. 890, the dispute 

resolution process should be available to address all disputes related to the planning 

process, both procedural and substantive.84 This does not mean, as Duke implies, that 

any changes to the plan that may result from dispute resolution procedures become a 

binding obligation to build. In requiring a dispute resolution process for planning-related 

disputes, the Commission is not asserting any greater authority than it otherwise has to 

 84 See id. at P 501. 
Docket No. RM05-17-001, et al. - 112 -

ensure that transmission providers comply with their tariff obligations to expand their 

systems to meet the needs of their customers. The dispute resolution process therefore 

does not change the rights or obligations otherwise established in the pro forma OATT. 

As we reiterate above, the Attachment K planning process does not place an affirmative 

obligation on the transmission provider to build upgrades identified in a plan. The tariff 

requirements regarding the construction of new facilities are covered in other portions of 

the pro forma OATT, as discussed above. 

g. Regional Participation

222. In order to satisfy the regional participation principle, transmission providers must 

coordinate with interconnected systems to (1) share system plans to ensure that they are 

simultaneously feasible and otherwise use consistent assumptions and data and (2) 

identify system enhancements that could relieve congestion or integrate new resources. 

The Commission explained that the specific features of the regional planning effort 

should take account of and accommodate, where appropriate, existing institutions, as well 

as physical characteristics of the region and historical practices. 

Requests for Rehearing and Clarification

223. TDU Systems ask the Commission to clarify that the regional participation 

principle requires both transmission providers and other stakeholders to be actively 

involved in regional planning activities. TDU Systems contend that some language in 

Order No. 890 could be read to limit regional coordination to transmission providers.85 

 85 Citing id. at P 523. 
Docket No. RM05-17-001, et al. - 113 -

224. National Grid asks the Commission to expand the regional participation principle 

to expressly require regions to adopt interregional planning processes subject to the same 

nine principles applicable to individual regions. National Grid argues that there will be 

little improvement in the area of interregional planning, and that disputes will continue to 

arise, in the absence of generic action by the Commission. 

225. EPSA suggests that Commission staff be designated to attend the development of 

all regional planning processes in non-RTO areas, in order to ensure adequate and timely 

oversight and accountability during the development stage, as well as to ensure that all 

stakeholders have a viable chance to participate in the development of their own regional 

planning processes.

Commission Determination

226. The Commission clarifies in response to TDU Systems that, while the obligation 

to engage in regional coordination is directed to transmission providers, participation in 

such processes is not limited to transmission providers. In Order No. 890, the 

Commission required transmission providers to develop a planning process that facilitates 

regional participation and required that process, in turn, to be open to all interested 

customers and stakeholders. In response to National Grid, we emphasize that effective 

regional planning should include coordination among regions. As the Commission 

explained in Order No. 890, the identification of relevant regions and sub-regions will 

depend on the integrated nature of the power grid and the particular reliability or resource 
Docket No. RM05-17-001, et al. - 114 -

issues affecting individual regions and sub-regions.86 Each of these regions and subregions should coordinate as necessary to share data, information and assumptions to 

maintain reliability and allow customers to consider resource options that span the 

regions. 

227. We decline EPSA’s suggestion to direct Commission staff to attend the 

development of all regional planning processes in non-RTO areas. Commission staff has 

organized and attended a total of seven transmission planning technical conferences 

around the country, and engaged in numerous other meetings, phone calls and 

discussions, in order to assist transmission providers and customers in the development of 

planning processes that comply with the planning requirements of Order No. 890.87 

Transmission providers and stakeholders alike actively participated in these conferences. 

Any concerns regarding the inability of interested parties to participate in the 

development process can be raised on Commission review of the Attachment K 

compliance filings. 

 86 See id. at P 627. 

87 The staff technical conferences were held on: June 4-7, 2007 in Little Rock, AR 

and October 1-2, 2007 in Atlanta, GA, covering the Southeast including Southwest 

Power Pool and its members; June 13, 2007 in Park City, UT, covering the Northwest 

and June 26, 2007 in Phoenix, AZ, covering the Southwest and California, as well as 

October 23-24, 2007 in Denver, CO, covering both of these regions; and June 28-29, 

2007 in Pittsburgh, PA and October 15-16, 2007 in Boston, MA, covering the ISO New 

England, NYISO, PJM, MISO, and Mid-Continent Area Power Pool subregions. 
Docket No. RM05-17-001, et al. - 115 -

h. Economic Planning Studies

228. In order to satisfy the economic planning studies principle, transmission providers 

must take into account both reliability and economic considerations in their Attachment 

K planning processes. The Commission stated that the purpose of this principle is to 

ensure that customers may request studies that evaluate potential upgrades and other 

investments that could reduce congestion or integrate new resources and loads on an 

aggregated or regional basis, and not to assign cost responsibility for any investments or 

otherwise determine whether they should be implemented.88 The Commission 

determined that customers should be permitted to choose the studies that are of the 

greatest value to them, directing transmission providers to develop a means to allow the 

transmission provider and stakeholders to cluster or batch requests for economic planning 

studies so that the transmission provider may perform the studies in the most efficient 

manner. Customers must be given the right to request a defined number of high priority 

studies annually, the costs of which would be recovered as a part of the overall pro forma

OATT cost of service.

Requests for Rehearing and Clarification

229. TDU Systems ask the Commission to clarify that the expansion of economic 

planning required in Order No. 890 to include integration of new resources and loads did 

not supplant the need to study both short-term and long-term congestion. TDU Systems 

 88 The Commission addressed the issue of cost allocation in a separate principle, 

discussed below. 
Docket No. RM05-17-001, et al. - 116 -

further argue that any measure of congestion in the economic study process must be 

based on total gross congestion rather than hedgeable congestion, which they argue is 

unrealistic. TDU Systems state that in PJM, for example, congestion includes only that 

which cannot be hedged through financial instruments. TDU Systems contend that this 

ignores the significant costs of purchasing the financial instruments necessary to hedge 

the congestion and that gross congestion more accurately reflects what load pays for 

congestion. 

230. TDU Systems also ask the Commission to clarify that each transmission provider 

must specify in its Attachment K the process for requesting and selecting economic 

planning studies and the number of high priority studies that will be paid for by the 

transmission provider. TDU Systems argue that the economic study process, including 

selection of which studies to perform, must be developed in collaboration with customers 

and other interested stakeholders. TDU Systems, as well as NRECA, suggest that the 

high priority studies only include those requested by non-affiliated customers so that the 

economic planning process is not usurped by the transmission provider and its affiliates. 

231. AWEA asks the Commission to require transmission providers to engage in 

economic planning of upgrades to address the lumpiness of transmission investments. 

AWEA argues that the needs of native load groups, multiple generation projects, and load 

centers cannot be optimized unless they are combined in a single transmission plan. 

AWEA contends that comparability requires planning to provide capacity for OATT 

customers so that the cost of large, lumpy upgrades are not all assigned to single projects. 

232. EEI requests clarification that the stakeholders’ right to designate high priority 
Docket No. RM05-17-001, et al. - 117 -

studies applies to stakeholders as a group, not to individual stakeholders. EEI asserts that 

allowing individual stakeholders to designate specified numbers of studies would be 

impractical and inconsistent with the goal of an aggregated or regional approach to 

planning. Entergy asks the Commission to clarify that economic studies must be related 

to congestion issues affecting a stakeholder and not simply attempts to obtain competitive 

sensitive information about another party’s resources and loads. Entergy suggests that a 

party requesting a study be required to explain the basis for its request and how the study 

relates to its own transmission service needs. 

233. MISO, NYISO and National Grid ask the Commission to clarify that, within an 

RTO or ISO, requests for congestion studies must be made and approved through existing 

stakeholder processes. Otherwise, National Grid argues that studies may be tailor-made 

to the parochial interests of the requestor with limited subregional scope, which in its 

view would inhibit the regional planning process and tax RTO and ISO resources. 

NYISO requests further clarification that transmission-owning members of an RTO or 

ISO are not required to perform separate, individual congestion studies at the request of 

customers. 

234. Southern argues that the economic planning requirements of Order No. 890 should 

be based on the Commission’s jurisdiction to ensure just and reasonable rates, since the 

information from such studies could facilitate customers’ ability to optimize their future 

transmission service. Southern contends that neither Good Utility Practice nor 

comparability support adoption of the economic study requirements of Order No. 890. 

Southern states that its transmission function planners perform no congestion analysis 
Docket No. RM05-17-001, et al. - 118 -

and, instead, plan the system to satisfy reliability requirements and to meet the needs of 

firm transmission customers. 

Commission Determination

235. The Commission affirms the decision in Order No. 890 to allow stakeholders the 

right to request a defined number of high priority studies annually to address congestion 

and/or the integration of new resources or loads.89 The expansion of the economic 

planning principle in Order No. 890 did not supplant the need to study both short-term 

and long-term congestion, if requested by a stakeholder, as TDU Systems suggest. 

Similarly, the choice to study hedgeable or gross congestion is the choice of the 

requesting stakeholder or group of stakeholders. The intent of the economic planning 

principle is to allow stakeholders, and not the transmission provider, to identify the 

studies that are of the greatest value to them. This provides sufficient flexibility to 

address customer needs, including the study of large, lumpy transmission projects, as 

requested by AWEA. 

236. We agree with petitioners that the transmission provider’s Attachment K must 

clearly describe the process by which economic planning studies can be requested and 

how they will be prioritized.90 We also agree that stakeholders as a group have the right 

to request the defined number of high priority studies to be paid for by the transmission 

 89 Order No. 890 at P 547. 

90 RTOs and ISOs may continue to use existing stakeholder processes to identify 

which economic planning studies will be of most benefit to the region, provided such 

processes are otherwise consistent with the requirements of Order No. 890. 
Docket No. RM05-17-001, et al. - 119 -

provider.91 As a result, transmission providers must develop a means to allow the 

transmission provider and customers to cluster or batch requests for economic planning 

studies so that the transmission provider may perform the studies in the most efficient 

manner. By limiting the economic planning principle to a defined number of high 

priority studies annually, the Commission did not intend to preclude stakeholders from 

requesting additional studies. To provide appropriate financial incentives, the 

stakeholder(s) requesting such additional studies would be responsible for paying the cost 

of such studies.92 

237. We decline to generically limit the scope of economic planning studies as 

requested by Entergy. Studies may be requested to address congestion issues or the 

integration of new resources/loads. The limited number of high priority studies available 

should restrict the ability of stakeholders to use these studies for other purposes, since 

stakeholders and the transmission providers will be working together to determine which 

studies will be pursued. We also reject petitioners’ suggestion that the requests made by 

a transmission provider’s affiliates for economic planning studies should not count 

toward the defined number of high priority studies. The transmission provider’s affiliates 

should be treated like any other stakeholder and, therefore, their requests for studies 

should be considered comparably, pursuant to the process outlined in the transmission 

provider’s Attachment K. 

 91 See id. at P 547. 

92 See id. at P 546. 
Docket No. RM05-17-001, et al. - 120 -

238. We clarify in response to NYISO that it is the transmission provider’s obligation 

to perform economic planning studies, just as it is the transmission provider’s obligation 

to comply with other aspects of the planning process required in Order No. 890. As we 

explain above, RTOs and ISOs have flexibility in determining how to fulfill their 

planning-related obligations and may delegate certain responsibilities to their 

transmission-owning members or otherwise incorporate the processes of their members 

into the RTO/ISO planning process. To the extent an RTO or ISO delegates any of its 

responsibilities in the context of economic planning, it will be the obligation of the RTO 

or ISO to ensure ultimate compliance with the requirements of Order No. 890. 

239. We disagree with Southern that the Commission may only require transmission 

providers to undertake economic planning studies pursuant to its authority to ensure just 

and reasonable rates. Consistent with our authority under FPA section 206, the 

Commission acted in Order No. 890 to limit the opportunities for undue discrimination in 

the area of transmission planning and to ensure that comparable service is provided by all 

public utility transmission providers. As the Commission explained in Order No. 890, a 

prudent vertically-integrated transmission provider will plan not only to maintain 

reliability, but also consider whether transmission upgrades or other investments can 

reduce the overall costs of serving native load.93 To represent Good Utility Practice and 

provide comparable service, the transmission planning process under the pro forma

OATT therefore must consider both reliability and economic considerations.

 93 See id. at P 542. 
Docket No. RM05-17-001, et al. - 121 -

240. Southern states merely that its transmission planners do not perform congestion 

analyses in particular, not that they disregard economics in the planning of their system. 

Prudent vertically-integrated transmission providers take into consideration whether 

upgrades or other investments could allow them to meet the needs of their customers on a 

more economic basis. Through the economic planning principle, we simply require 

Southern, and other transmission providers, to make available to their customers services 

that are comparable to those they are performing on behalf of their native load. We 

therefore affirm the decision in Order No. 890 to require transmission providers to 

perform economic planning studies at the request of their stakeholders.

i. Cost Allocation for New Projects

241. In order to satisfy the cost allocation principle, transmission providers must 

address in their Attachment K planning processes the allocation of costs of new facilities. 

These cost allocation methodologies are intended to apply to projects that do not fit under 

existing rate structures, such as regional projects involving several transmission owners 

or economic projects that are identified through the study process, rather than projects 

built in response to individual requests for service. The Commission declined to impose 

a particular allocation methodology for such projects and, instead, identified three factors 

to be considered upon review of cost allocation proposals. First, we consider whether a 

cost allocation proposal fairly assigns costs among participants, including those who 

cause them to be incurred and those who otherwise benefit from them. Second, we 

consider whether a cost allocation proposal provides adequate incentives to construct new 
Docket No. RM05-17-001, et al. - 122 -

transmission. Third, we consider whether the proposal is generally supported by state 

authorities and participants across the region. 

Requests for Rehearing and Clarification

242. PSEG questions whether the Commission intended in Order No. 890 to mandate 

the funding of economic projects through the cost allocation methodology developed as 

part of the transmission provider’s planning process. PSEG argues that this would be 

inappropriate since certain transmission providers, such as NYISO, currently only 

conduct reliability planning, not economic planning. PSEG argues that the most 

transmission providers should be obligated to do is present information so that market 

participants may respond to economic issues. In its view, introduction of regulated 

transmission solutions in response to economic enhancements destroys incentives for 

private investment and precludes the possibility of other market-based solutions, such as 

generation and demand side management, from providing a more efficient solution. 

PSEG objects to the Commission’s reliance on the PJM “market efficiency” proposal, 

arguing that the Commission’s action in that proceeding was conditioned on PJM 

submitting a compliance filing to clarify aspects of its proposal.94 

243. To the extent the Commission requires ratepayer funding of economic upgrades, 

PSEG suggests that market participants who are asked to pay be allowed to vote on 

acceptance of cost allocations for the project. PSEG suggests that construction of a 

 94 Citing id. at P 545 (citing PJM Interconnection, LLC, 117 FERC ¶ 61,218 

(2006), reh’g pending). 
Docket No. RM05-17-001, et al. - 123 -

project be approved only if a certain percentage vote in favor of building the project and 

no more than a certain percentage vote against building the project. With regard to 

reliability upgrades, PSEG argues that there are also insufficient checks in place to ensure 

that RTOs and ISOs do not undertake expensive upgrades to solve a reliability criteria 

violation when simpler, less expensive projects may suffice. PSEG therefore requests 

that the Commission require that a cost-benefit analysis be conducted for both reliability 

and economic transmission projects. 

244. TDU Systems argue that the costs of all network upgrades identified in the 

transmission plan be allocated and recovered on a rolled-in basis. TDU System maintain 

that rolled-in rate treatment for such upgrades would minimize disputes and encourage 

expansion by providing certainty for transmission providers. TDU Systems contend that 

failure to mandate rolled-in cost recovery for network upgrades identified in the 

transmission plan defaults on the Commission’s obligations under FPA section 217 to 

promote expansion to support the ability of LSEs to meet their service obligations. 

245. EPSA argues that any cost allocation of economic projects must be based on clear 

and balanced economic metrics, calculations, and assumptions. EPSA objects to any 

requirement that cost allocation provisions for economic projects create a funding 

mechanism for proponents of such projects, arguing that this would be inconsistent with 

the Commission’s statements that transmission providers are not under an obligation to 

fund or build upgrades identified in the transmission plan.

246. Old Dominion urges the Commission to clarify Order No. 890 by elaborating and 

expanding upon the factors the Commission will consider in addressing cost allocation 
Docket No. RM05-17-001, et al. - 124 -

for new transmission. Old Dominion suggests that the following issues be considered in 

evaluating whether a cost allocation proposal is reasonable: facilitation of regional 

market development; benefits over the life of the facility; reliability benefits beyond 

resolution of the triggering reliability violation; reduction in capacity, energy, and reserve 

costs from reliability upgrades; consideration of benefits that may not be readily 

quantifiable; need for rate certainty; and, avoidance of rate shock. Old Dominion argues 

that elaboration on these factors will help stakeholders reach consensus on cost allocation 

issues. Old Dominion also seeks clarification that the cost allocation principle applies 

equally to projects that are built by a single transmission owner, but that have a regional 

impact.

247. With regard to interregional cost allocation, Old Dominion and TDU Systems 

argue that the Commission should require the cost allocation criteria identified in the 

transmission provider’s Attachment K to apply to transmission facilities in one region 

that provide benefits to customers in another region.95 Old Dominion contends that 

omission of cross-border allocation requirements in the OATT is inconsistent with basic 

cost causation principles as expressed in Order No. 890 itself.96 TDU Systems argue that 

regions will benefit from up-front resolution of cross-border allocation issues, just as 

transmission providers benefit from up-front resolution of regional cost allocation issues.

 95 Citing Midwest Ind. Sys. Operator, Inc., 117 FERC ¶ 61,241 (2006); Midwest 

Ind. Sys. Operator, Inc., 109 FERC ¶ 61,243 (2004). 

96 Citing Order No. 890 at P 559. 
Docket No. RM05-17-001, et al. - 125 -

248. E.ON U.S. asks the Commission to clarify that the cost allocation principle may 

not be used to shift transmission construction costs to border utilities that receive no 

direct benefit from the construction. E.ON U.S. contends that the transmission customers 

of each RTO or ISO already pay for the cost of upgrades through transmission rates 

charged by the RTO or ISO. 

249. Duke does not object to the cost allocation principle, but notes the difficulties that 

have been experienced in reaching consensus in RTOs and ISOs and asks the 

Commission to consider delaying the requirement beyond the 210-day due date if 

regional consensus cannot be reached. In the alternative, Duke suggests that transmission 

providers be allowed to submit allocation proposals as separate informational strawmen 

that will serve as a vehicle for further discussion in the region. 

Commission Determination

250. The Commission affirms the decision in Order No. 890 to require transmission 

providers to address in their Attachment K planning processes cost allocation for new 

facilities that do not fit under existing structures. Transmission providers and customers 

cannot be expected to support the construction of new transmission unless they 

understand who will pay the associated costs. This applies equally to reliability and 

economic projects, whether built by a single transmission owner or through joint 

ownership. However, mandatory rolled-in rate treatment for all network upgrades 

identified in the transmission plans, as suggested by TDU Systems, is not necessarily 

appropriate. The Commission is fulfilling its obligations under FPA section 217 to 

support expansion of the grid by requiring transmission providers to address in their 
Docket No. RM05-17-001, et al. - 126 -

Attachment K processes how costs will be allocated for reliability and economic projects, 

which we will address on a case-by-case basis.

251. We disagree with PSEG’s contention that economic projects should be excluded 

from the cost allocation provisions of the pro forma OATT. As the Commission noted in 

Order No. 890, the issue of cost allocation is particularly important as applied to 

economic upgrades.97 Participants seeking to support new transmission investment need 

some degree of certainty regarding cost allocation to pursue that investment. We 

therefore agree with EPSA that the details of proposed cost allocation methodologies 

must be clearly defined, but emphasize that adoption of a cost allocation methodology 

will not impose an obligation to build. As we reiterate above, identification of an 

upgrade (reliability or economic) in the transmission plan does not trigger an obligation 

to build under the Attachment K planning process. Up-front identification of how the 

cost of a facility will be allocated will, however, allow transmission providers, customers, 

and potential investors to make the decision whether or not to build on an informed basis.

252. As explained above, all transmission providers, including RTOs and ISOs, must 

undertake economic planning studies at the request of stakeholders. Within an RTO or 

ISO, stakeholder processes can be used to determine whether to pursue either economic 

or reliability upgrades and, thus, voting mechanisms such as those suggested by PSEG 

could be adopted if stakeholders desire. If the transmission provider or stakeholders 

determine that other solutions are superior to transmission upgrades, they may pursue 

 97 See id. at P 542. 
Docket No. RM05-17-001, et al. - 127 -

those solutions instead and integrate them into the transmission plan. The transmission 

planning process established in Order No. 890 does not dictate that particular investments 

be made, rather that an open, coordinated, and transparent process be adopted to govern 

the decision-making process.

253. We decline to adopt Old Dominion’s suggestion to define in more detail the 

factors to be considered in evaluating whether a cost allocation proposal is reasonable. 

We intend to allow regional flexibility regarding cost allocation and will consider each 

proposal on a case-by-case basis. While we would expect many of the considerations 

raised by Old Dominion to be relevant, since they fall within the three factors identified 

by the Commission, the merits of each proposal will be analyzed in light of the facts and 

circumstances surrounding the proposal. Similarly, issues regarding cross-border 

allocation or the potential shifting of costs to border utilities are best addressed in the 

context of a particular proposal. 

254. Finally, we deny Duke’s request to extend the Attachment K compliance deadline 

as it relates to cost allocation proposals. We acknowledge that resolution of cost 

allocation issues are difficult, as are many of the issues raised in the context of 

transmission planning. The Commission therefore granted transmission providers an 

extension of the Attachment K filing deadline in order to allow for a second round of 

staff technical conferences to review progress made on draft compliance filings.98 

 98 See Preventing Undue Discrimination and Preference in Transmission Service, 

120 FERC ¶ 61,103 (2007). 
Docket No. RM05-17-001, et al. - 128 -

Commission staff also issued a white paper to further assist transmission providers in the 

drafting of Attachment K tariff language.99 We believe that transmission providers have 

had adequate time and guidance to complete the drafting of their Attachment K proposals 

prior to the revised filing deadline. 

j. Additional Issues Relating to Planning Reform

(1) Independent Third-Party Coordinator

255. The Commission declined in Order No. 890 to require the use of an independent 

third party coordinator for transmission planning activities, but encouraged transmission 

providers and their customers to explore aspects of planning where the use of an 

independent coordinator would be beneficial and to incorporate those aspects in their 

planning processes. 

 Requests for Rehearing and Clarification

256. Old Dominion argues that the Commission erred by failing to recognize the need 

for an independent third party to oversee transmission planning. With regard to RTOs in 

particular, Old Dominion seeks confirmation that market monitoring units have the 

requisite independence and authority to investigate and address undue influence in the 

transmission planning process. Old Dominion asks the Commission to direct RTOs to 

include in their compliance filings a description of the market monitor’s ability to 

identify and address undue influence in the transmission planning process. Old 

 99 Transmission Planning Process Staff White Paper, Docket No RM05-17-000, et 

al. (August 2, 2007). 
Docket No. RM05-17-001, et al. - 129 -

Dominion argues that the ability for customers to file a section 206 complaint is 

insufficient and can only bring about prospective changes in monitoring, failing to 

remedy the potential exercise of transmission market power in transmission planning.

257. TDU Systems support the decision not to mandate use of a third-party facilitator in 

the transmission planning process and seek clarification that, to the extend a third-party 

facilitator is used, related costs can be included in a transmission provider’s cost of 

service only if all transmission customers agree or if a cost-benefit analysis supports the 

use of the facilitator. TDU Systems contend this would avoid disputes regarding the 

wisdom of using a third-party facilitator if a significant segment of transmission 

customers object.

Commission Determination

258. We disagree with Old Dominion that we did not adequately address the potential 

role of an independent third party in transmission planning in Order No. 890. As the 

Commission explained, there may be benefits to be gained from independent third party 

oversight, but transmission providers, customers, and other stakeholders should 

determine for themselves in developing the transmission provider’s planning process 

whether, and if so how, to utilize an independent third party.100 This would include 

considerations regarding recovery of costs associated with the use of a third-party in the 

transmission planning process and, within an RTO, the role of the market monitor, if any, 

in that process.

 100 See Order No. 890 at P 567. 
Docket No. RM05-17-001, et al. - 130 -

(2) Open Season for Joint Ownership

259. Although the Commission acknowledged in Order No. 890 the benefits of joint 

ownership of transmission facilities, the Commission declined to mandate open season 

procedures to allow market participants to participate in joint ownership. The 

Commission recognized that there may be reasons, given the complexity of the 

transmission grid and changing conditions of supply and demand for power, why any 

given facility identified in a transmission plan may not be ultimately constructed. If a 

transmission provider declines to construct an identified upgrade, the Commission 

encouraged customers and third parties to consider, either individually or jointly, 

development and ownership of a project to the extent consistent with applicable state law. 

Requests for Rehearing and Clarification

260. FMPA asks the Commission to order transmission providers to make available 

opportunities to jointly participate in the ownership of new transmission facilities to 

achieve the benefits of joint ownership recognized by the Commission and remedy the 

discriminatory and anticompetitive effects of excluding some public power utilities from 

ownership. In the alternative, FMPA asks the Commission to take the lesser step of 

establishing presumptions that transmission customers are allowed to jointly invest in 

new grid transmission facilities and that transmission providers are not entitled to rate 

incentives if they exclude some systems that are willing to invest in transmission. FMPA 

argues that such presumptions will prevent recalcitrant transmission owners from 

refusing participation or from using their control of the grid to extract unreasonable terms 

and conditions, while allowing them to protect any legitimate interests they may have.
Docket No. RM05-17-001, et al. - 131 -

261. TDU Systems argue that diversification of ownership of the grid, facilitated by 

mandatory open seasons for joint or third-party ownership, would provide a structural 

remedy to the vertical market power enjoyed by many transmission providers. They 

contend that the inadequacy of the grid, combined with the unwillingness or inability of 

transmission providers to invest in new infrastructure, has allowed many transmission 

providers to retain generation dominance on their systems and unduly discriminate 

against transmission customers. TDU Systems argue that FPA sections 205 and 206 give 

the Commission adequate authority to mitigate this market power by either requiring 

open seasons for joint ownership or third-party ownership or by conditioning marketbased rate authority or incentive rates on agreements to offer such open seasons. 

262. TDU Systems argue that the Commission at a minimum should require 

transmission providers to hold open seasons for third-party construction where a 

transmission provider is unwilling or unable to construct a new facility that is identified 

as needed in the planning process. TDU Systems further request that the Commission 

modify the pro forma OATT to include an explicit obligation to interconnect joint or 

third-party facilities constructed in response to projects identified in the local or regional 

planning process.

Commission Determination

263. The Commission affirms the decision in Order No. 890 not to mandate procedures 

for joint ownership of transmission facilities. We continue to believe that there are 

benefits to joint ownership, particularly for large backbone transmission facilities, and 

encourage transmission providers, customers, and third parties to consider joint 
Docket No. RM05-17-001, et al. - 132 -

development and ownership as appropriate. The Commission acknowledged in Order 

No. 890, however, that joint ownership can increase the complexity of planning and 

developing a transmission project and we are sensitive to concerns that formal open 

seasons can add to that complexity.101 We therefore decline to mandate the generic use 

of open seasons or establish presumptions, as suggested by FMPA, regarding their use. 

264. We also reject TDU Systems’ suggestion that declining to mandate open seasons 

for joint ownership leaves the transmission provider with unmitigated vertical market 

power. Transmission providers are required under the OATT to make transfer capability 

available on a non-discriminatory basis and to expand their systems as necessary to 

accommodate requests for transmission service, including service associated with new 

customer-owned transmission facilities. In the absence of specific evidence of undue 

discrimination by a transmission provider, we do not believe mandating open seasons or 

altering our incentive rate program is necessary to mitigate market power in the provision 

of transmission service. Customers and third parties remain free to develop and construct 

facilities as they see fit and, through the Attachment K planning process, incorporate the 

development of those facilities into the transmission plan. 

 101 Id. at P 594. 
Docket No. RM05-17-001, et al. - 133 -

C. Transmission Pricing

1. Energy and Generation Imbalances

a. Tiered Approach to Imbalance Penalties in the OATT

265. In Order 890, the Commission modified Schedule 4 of the pro forma OATT 

regarding treatment of energy imbalances and adopted a separate pro forma OATT 

schedule (Schedule 9) to govern treatment of generator imbalances. The Commission 

determined that charges for both energy and generator imbalances must follow 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. 

266. The Commission also determined that the same tiered approach should be used for 

both energy and generator imbalances. Imbalances of less than or equal to 1.5 percent of 

the scheduled energy (or two megawatts, whichever is larger) are to be netted on a 

monthly basis and settled financially at 100 percent of incremental cost at the end of each 

month. Imbalances between 1.5 and 7.5 percent of the scheduled amounts (or 2 to 10 

megawatts, whichever is larger) are to be settled financially at 90 percent of the 

transmission provider’s system incremental 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. 
Docket No. RM05-17-001, et al. - 134 -

Finally, imbalances greater than 7.5 percent of the scheduled amounts (or 10 megawatts, 

whichever is larger) are to be settled at 75 percent of the system incremental cost for 

overscheduling imbalances or 125 percent of the incremental cost for underscheduling 

imbalances. 

Requests for Rehearing and Clarification

267. TAPS contends that the use of the phrase “same imbalance” in the language of 

Schedules 4 and 9 is imprecise and could lead to some confusion. TAPS asks that the 

Commission amend the language of Schedules 4 and 9 to be consistent with footnote 387 

of Order No. 890, in which the Commission states that a transmission provider may only 

charge the penalty percent adder to the incremental cost for either an hourly generator 

imbalance or an hourly energy imbalance for the same imbalance.102 TAPS suggests 

modifying the first paragraph of Schedule 9 to read: “The Transmission Provider may 

charge a Transmission Customer a penalty for either hourly generator imbalances under 

this Schedule or hourly energy imbalances under Schedule 4 for the imbalances occurring 

during the same hour, but not both (unless the imbalances aggravate rather than offset 

each other).” TAPS requests that the similar change be made to corresponding language 

in Schedule 4. 

268. Steel Manufacturers Association argues that the Commission should abandon the 

dead band/penalty mechanism for energy imbalances and adopt instead the basic 

framework employed in the organized markets, where a customer pays or is paid the 

 102 See id. at P 632, n.387. 
Docket No. RM05-17-001, et al. - 135 -

provider’s incremental cost for imbalances. Steel Manufacturers Association contends 

that, in the organized markets, the Commission recognizes that pricing imbalances at the 

real-time price of energy provides adequate incentives to ensure that customers schedule 

accurately. Steel Manufacturers Association argues that the Commission failed to justify 

application of a different policy, i.e., escalating penalties, under the pro forma OATT. 

Steel Manufacturers Association contends that there is no evidence of negative reliability 

impacts in the organized markets due to the lack of inaccurate scheduling, nor is there 

evidence of customers taking advantage of the transmission provider by leaning on the 

transmission grid. Steel Manufacturers Association further contends that similar 

imbalance pricing policies should apply in both market structures. Steel Manufacturers 

Association argues that clearing imbalances outside of the organized markets at the 

transmission provider’s marginal cost for the hour is sufficient for that purpose. If the 

Commission retains a Schedule 4 with a bandwidth and penalty structure, Steel 

Manufacturers Association requests that the Commission institute a larger bandwidth of, 

at minimum, 10 percent for small wholesale customers and discrete retail loads in order 

to provide some measure of relief for those customers. 

269. Steel Manufacturers Association also requests that end-use customers that provide 

ancillary services through demand response be exempt from imbalance charges for 

imbalances created as a result of the use of the demand response. Steel Manufacturers 

Association contends that an end-use customer that modifies its usage in real-time, in 

order to be price responsive or respond to a system operator’s call to curtail load, will 

create energy imbalances. If that end-use customer is assessed a penalty for those energy 
Docket No. RM05-17-001, et al. - 136 -

imbalances, Steel Manufacturers Association argues that it will have little incentive to 

provide an ancillary service such as spinning reserve or regulation through demand 

response. Steel Manufacturers Association suggests that the Commission revise the 

energy imbalance provisions to encourage, rather than discourage, demand response. 

Commission Determination

270. The Commission affirms the decision in Order No. 890 to adopt a tiered 

bandwidth approach for both energy and generation imbalances. We disagree with Steel 

Manufacturers Association that simply paying the transmission provider’s incremental 

cost for energy imbalances would provide adequate incentives for customers to schedule 

accurately under the pro forma OATT. Market structures in place within RTOs and ISOs 

are fundamentally different from those in non-RTO/ISO regions. In the organized 

markets, system operators generally use a five minute dispatch with multiple suppliers of 

imbalance energy responding to system operator instructions. Suppliers and customers 

alike are therefore able to respond to real-time changes in locational prices that reflect 

both the cost of energy and congestion, which serves to discipline transmission customers 

and generators from deviating from their instructed level. This is not the case outside of 

the organized markets and, therefore, other incentives must be provided to discourage 

deviations. 

271. We also decline to institute a larger bandwidth or eliminate the penalty structure 

for energy imbalances caused by small wholesale customers or discrete loads. Use of the 

bandwidths adopted in Order No. 890, with the 2 MW and 10 MW minimums for the first 

and second penalty bands, appropriately links increased deviations and potential 
Docket No. RM05-17-001, et al. - 137 -

reliability impacts on the system while allowing increased tolerance to smaller customers. 

We note, moreever, that the 2 MW minimum specified in Order 890 does allow for a 10 

percent bandwidth, as Steel Manufacturers Association requests, for loads 20 MW or 

less. 

272. We agree with Steel Manufacturers Association, however, that end-use customers 

providing an ancillary service through demand response should generally not be subject 

to penalties for imbalances created as a result of providing the ancillary service. In this 

respect, customers using demand resources for ancillary services should not be treated 

differently from customers using generating units to provide ancillary services. The 

mechanisms for addressing the self-provision or third-party provision of ancillary 

services have developed outside the pro forma OATT and we will not disrupt these 

developments. Thus, there is no need to revise the pro forma OATT, as Steel 

Manufacturers Association suggests, since existing practices for third-party provided 

ancillary services should apply to demand resources as they apply to generating 

resources. 

273. We agree with TAPS that the reference to “same imbalance” in Schedules 4 and 9 

could lead to confusion and amend the language of those schedules accordingly. We 

revise the language of Schedules 4 and 9 to clarify that the transmission provider may 

charge a transmission customer a penalty for either hourly generator imbalances under 

Schedule 9 or hourly energy imbalances under Schedule 4 for imbalances occurring 

during the same hour, but not both unless the imbalances aggravate rather than offset 

each other. 
Docket No. RM05-17-001, et al. - 138 -

b. Generator Imbalance Penalties

274. The Commission concluded in Order No. 890 that formalizing generator 

imbalance provisions in the pro forma OATT will standardize the future treatment of 

such imbalances from the wide variety of generator imbalance provisions that previously 

existed in various generator interconnection agreements. Standardizing generator 

imbalance provisions, in turn, should lessen the potential for undue discrimination, 

increase transparency and reduce confusion in the industry. The Commission 

emphasized, however, that it was not abrogating existing generator imbalance agreements 

in this rulemaking proceeding. 

275. With regard to intermittent resources, the Commission provided that such 

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. The Commission defined intermittent resources for this purpose as “an 

electric generator that is not dispatchable and cannot store its fuel source and therefore 

cannot respond to changes in system demand or respond to transmission security 

constraints.” The Commission also determined that all generators should be excused 

from imbalance penalties that occur due to directed reliability actions by a generator to 

correct system frequency. 

Requests for Rehearing and Clarification

276. A number of petitioners seek rehearing and/or clarification of the generator 

imbalance reforms adopted in Order No. 890. Sempra Global asks that the Commission 

revise section 3 of the pro forma OATT to make clear that generator imbalance service 
Docket No. RM05-17-001, et al. - 139 -

must be offered for any transmission service used to deliver energy from a generator 

located within the transmission provider’s control area, as required in Schedule 

9. Sempra Global argues that section 3 of the pro forma OATT is inconsistent with 

Schedule 9, since section 3 only requires a transmission provider to offer generator 

imbalance service to a transmission customer serving load within the transmission 

provider’s control area. 

277. EEI, Entergy, and Southern ask that the Commission clarify that a transmission 

provider is entitled to charge either the transmission customer or the generator for 

generator imbalance service when the customer takes transmission service to deliver 

energy to an off-system load. In their view, generator imbalance charges may only be 

assessed to a transmission customer under new Schedule 9. Southern and EEI argue that 

this may be inappropriate because in many instances the generator is responsible for the 

generator imbalance, not the transmission customer. If the generator sells energy to more 

than one customer, Southern and EEI contend that it will be virtually impossible to 

determine which transmission customer should be assessed a charge and how the billing 

would be determined. 

278. EEI and Southern propose changes to Schedule 9 to address these concerns. EEI 

asks the Commission to clarify that either the transmission customer or the generator 

must take generator imbalance service in connection with any off-system sale of energy 

and that the transmission provider has no obligation to provide transmission service on its 

system to an off-system load unless the transmission customer or the generator executes a 

service agreement committing to take generator imbalance service. Southern, however, 
Docket No. RM05-17-001, et al. - 140 -

argues that the Commission should require every generator, subject to the grandfathering 

provisions in Order No. 890, to execute a service agreement to take and pay for generator 

imbalance service pursuant to Schedule 9 of the OATT and be a transmission customer 

for such purposes. If the Commission does not do so, Southern asks in the alternative 

that the Commission clarify that transmission providers, subject to the grandfathering 

provisions of Order No. 890, have no obligation to provide transmission service from an 

on-system generator to an off-system load if such generator has not executed a service 

agreement under the transmission provider’s OATT providing for the generator to take 

and pay for generator imbalance service. 

279. PNM argues that transmission providers should not be required to provide 

generator imbalance service when doing so would impair reliability for the transmission 

provider. PNM contends that some control area operators may not be able to offer 

generator imbalance service unless they can procure balancing energy and associated 

capacity from another entity. PNM argues that the obligation to provide Schedule 9 

service should be contingent upon the transmission provider determining that it is able to 

provide this service based upon a system impact study. Even if the service can physically 

be provided, PNM states that placing a must-offer requirement in Schedule 9, particularly 

for the purpose of supplying imbalance energy for intermittent generation, may have 

unreasonable impacts on the supply resources operated by small host control areas. In 

PNM’s view, an absolute must-offer requirement for Schedule 9 could lead to 

proportionately heavy impacts on small transmission providers that are required to 

interconnect generation developed to serve distant urban areas within large control areas. 
Docket No. RM05-17-001, et al. - 141 -

280. Joined by EEI and APS, PNM suggests that the Commission address these 

reliability concerns by allowing transmission providers the alternative of offering 

generators dynamic scheduling to change the responsibility for generator imbalances 

from specific generators. In cases where system reliability would be adversely affected, 

these petitioners contend that requiring a generator to accept a dynamic schedule of its 

output to the control area where the load is located, instead of requiring the transmission 

provider to provide generator imbalance service, would give the transmission provider a 

viable alternative to ensure that the generator’s imbalances are absorbed without 

compromising the reliability of the system where the generator is located, while also 

aligning the responsibility for supplying the imbalances associated with the parties that 

enjoy the benefit of the generation. 

281. EEI further argues that imbalance penalties fail to adequately compensate 

transmission providers for threats to system reliability caused by excessive generator 

imbalances and, therefore, use of dynamic scheduling would be appropriate. If the 

Commission does not allow the alternative of dynamic scheduling, APS requests that the 

Commission revise Schedule 9 to allow a transmission provider to identify the total 

amount of generator imbalance service it will offer. 

282. Other petitioners request clarification or rehearing regarding the Commission’s 

decision to exempt deviations associated with correcting system frequency from 

associated imbalance penalties. Xcel agrees with the Commission that generators should 

not be subject to imbalance penalties that occur when the generator is responding to 

reliability directives to correct frequency deviations and requests that this exception be 
Docket No. RM05-17-001, et al. - 142 -

expressly incorporated into the pro forma OATT. Xcel requests that the Commission 

either amend the Order No. 890 pro forma OATT on rehearing or clarify that a 

transmission provider can implement this practice by including such language in its 

compliance filing. Xcel suggests that the Commission also could, in the alternative, 

clarify that a transmission provider may implement this practice by posting a business 

practice indicating the transmission provider will waive such imbalance charges for 

generators correcting frequency deviations on a non-discriminatory basis. 

283. EPSA and TAPS request that the Commission expand the exemption to include 

other situations in which a generator is directed to be off-schedule by transmission 

operators, balancing authorities, or reliability coordinators. EPSA states, for example, 

that generators are often given directives by balancing authorities in order to reduce 

unscheduled flows on other systems and/or change line flows or voltage levels. TAPS 

argues that there should be an exception for generator imbalances resulting from 

transmission loading relief procedures (TLRs) or other transmission provider instructions, 

and for both the unexpected loss of a generating unit and the response of other generators 

to replace that unit under the reserve sharing arrangements, with resulting imbalances 

treated as being within the first deadband. TAPS argues that penalizing imbalances in the 

case of forced generation outages is particularly inappropriate since such charges do not 

give plant operators any better incentive to schedule accurately because unplanned unit 

outages by their very nature cannot be predicted and scheduled. 

284. Several petitioners request that the Commission clarify its definition of 

intermittent resources for purposes of applying imbalance charges. TAPS argues that 
Docket No. RM05-17-001, et al. - 143 -

intermittent generation should include test energy produced by newly completed units, so 

that generators are not unduly penalized (i.e., at third-tier penalty levels) for output 

variations that are inherently unpredictable. EEI and AMP-Ohio argue that run-of-river 

hydroelectric generating facilities should be deemed to be intermittent resources because 

their inability to store water to produce energy on demand satisfies the intention of the 

Order No. 890 definition, notwithstanding the fact that strictly speaking they do not have 

fuel sources. Northwestern, however, argues that run-of-river hydroelectric projects 

should not qualify as an intermittent resource because they generally do have the ability 

to predict flows and schedule accurately. NorthWestern also requests that the 

Commission specifically require utilities to update their tariffs to reflect this new 

definition. 

285. AMP-Ohio also argues that intermittent resources should be entirely exempt from 

imbalance penalties, arguing that it is unfair to impose any level of penalties on resources 

that are not dispatchable. In AMP-Ohio’s view, wind generators and run-of-river 

hydroelectric facilities alike depend on uncontrollable forces that affect their actual levels 

of generation. AMP-Ohio argues that fully exempting intermittent resources from 

imbalance penalties would not be unduly discriminatory vis-à-vis generators that are 

dispatchable since the different treatment would merely recognize their different 

circumstances. 

286. Finally, Entergy asks that the Commission confirm that transmission providers do 

not need to seek renewal of existing generator imbalance agreements. Entergy contends 

that it is unclear whether the procedures described in section IV.C of Order No. 890, 
Docket No. RM05-17-001, et al. - 144 -

regarding Commission consideration of previously-approved variations from the pro 

forma OATT, are intended to apply to generator imbalance agreements that have been 

previously negotiated between willing parties. 

Commission Determination

287. The Commission affirms the decision in Order No. 890 to adopt standardized 

generator imbalance provisions in Schedule 9 of the pro forma OATT. We agree with 

Sempra Global that section 3 of the pro forma OATT, as revised in Order No. 890, does 

not properly reflect that generator imbalance service must be offered for any transmission 

service used to deliver energy from a generator located within the transmission provider’s 

control area, as required in Schedule 9. We revise section 3 to make this clear. 

288. We also agree with EEI and Southern that, in certain circumstances, it may be 

appropriate for the transmission provider to allow a generator located within its control 

area to execute a service agreement for generator imbalance service, even if the generator 

is not otherwise a transmission customer. Without settling with the individual generator, 

it could be impossible for the transmission provider to determine which transmission 

customer should be assessed a charge and how the billing would be determined if a single 

generator was selling to multiple customers. We have revised Schedule 9 of the pro 

forma OATT to require the transmission provider to offer generator imbalance service to 

any generator in its control area (subject to the limitations discussed below). We clarify 

that, if a generator has executed a service agreement for generator imbalance service, any 

transmission customer scheduling from the generator will be deemed to have satisfied its 

obligation to purchase generator imbalance service under section 3 and Schedule 9. 
Docket No. RM05-17-001, et al. - 145 -

289. We further clarify that a transmission provider only has to provide generator 

imbalance service from its own resources to the extent that it is physically feasible to do 

so (i.e., the transmission provider is able to manage the additional potential imbalances 

without compromising reliability). It is not the Commission’s intent to require 

transmission providers to provide generator imbalance service from its resources when it 

would unreasonably impair reliability. Each transmission provider therefore may state on 

its OASIS the maximum amount of generator imbalance service it is able to offer from its 

resources, based on an analysis of the physical characteristics of its system. 

Alternatively, a transmission provider may consider requests for generator imbalance 

service on a case-by-case basis, performing as necessary a system impact study to 

determine the precise amount of additional generation it can accommodate and still 

reliably respond to the imbalances that could occur. 

290. This does not relieve the transmission provider of its obligation to provide 

generator imbalance service if it is able to acquire additional resources in order to do so. 

We acknowledge PNM’s concerns that some control area operators may only be able to 

provide generator imbalance service by procuring balancing energy and associated 

capacity from another entity. If it is not physically feasible for the transmission provider 

to offer generator imbalance service using its own resources, either because they do not 

exist or they are fully subscribed, the transmission provider must attempt to procure 

alternatives to provide the service, taking appropriate steps to offer an option that 

customers can use to satisfy their obligation to acquire generator imbalance service as a 

condition of taking transmission service. In the unlikely circumstance that there are no 
Docket No. RM05-17-001, et al. - 146 -

additional resources available to enable the transmission provider to meet its obligation 

for generator imbalance service, the transmission provider must accept the use of 

dynamic scheduling to the extent a transmission customer has negotiated appropriate 

arrangements with a neighboring control area.103 

291. We also reject requests to further exempt intermittent resources by eliminating 

imbalance penalties altogether for such resources. Generator imbalance charges are 

based on the incremental costs incurred by the transmission provider to respond to the 

generator’s imbalance. In the second tier, charges escalate somewhat to provide an 

incentive for generators not to deviate outside of the first tier. Without this penalty 

component, intermittent resources would not have any additional incentive to accurately 

schedule. At the same time, the Commission recognized that intermittent generators 

cannot always accurately follow their schedules and therefore exempted those resources 

from third-tier penalties. If given proper incentives, intermittent generators can improve 

their forecasting methods in order to submit more accurate schedules. Thus, we continue 

to believe this relaxed penalty structure strikes the right balance between the need to 

encourage accurate scheduling and the operating limitations of intermittent resources. 

292. We agree with EEI and AMP-Ohio that the definition of intermittent resources 

includes run-of-river hydroelectric units that do not store water used to generate 

electricity, i.e., for which instantaneous inflow equals instantaneous outflow. 

 103 The Commission addresses request to require transmission providers to offer 

dynamic scheduling as a new service under the pro forma OATT in section III.D.1.d. 
Docket No. RM05-17-001, et al. - 147 -

Hydroelectric units using storage, however, are not intermittent resources within the 

meaning of Schedule 9 of the pro forma OATT. The ability of those units to schedule 

their output is not as limited as intermittent resources. The same is true of newly 

completed generating units producing test energy. Under the pro forma OATT, 

generators do not have to submit final schedules until the morning of the prior operating 

day and may revise those schedules up until 20 minutes prior to the operating hour. We 

conclude that this provides sufficient flexibility for hydroelectric units using storage and 

newly completed units producing test energy to change their schedules to reflect 

forecasted output and that any charges resulting from remaining imbalances are just and 

reasonable under the reformed generator imbalance provisions of the pro forma OATT. 

293. We agree with Xcel that the exemption from generation imbalance penalties for 

generators responding to correct frequency decay should be expressly stated in the pro 

forma OATT. We also agree with EPSA and TAPS that a generator that deviates from its 

schedule due to directives by balancing authorities, transmission operators, and reliability 

coordinators should not be subject to the penalty component of imbalance charges and 

that this exemption should be expressly stated in Schedule 9. It would be inappropriate to 

assess imbalance penalties on generators following instructions to, for example, reduce 

unscheduled flows on other systems (such as a TLR) or change line flows or voltage 

levels, because such charges could create incentives not to respond and in turn 

compromise reliability. Similarly, generators responding to a reserve sharing event, with 

properly structured arrangements with transmission providers, should not be subject to 

penalties. We revise Schedule 9 accordingly. 
Docket No. RM05-17-001, et al. - 148 -

294. We decline, however, to carve out an exception for imbalances associated with the 

loss of a generating unit itself. We disagree with TAPS that penalizing imbalances in the 

case of forced generation outages does not give plant operators any better incentive to 

schedule accurately. Appropriately designed penalties provide a proper incentive for 

generators to reduce instances of forced outage by, for example, properly maintaining 

their facilities and therefore adhere to their schedules. 

295. Finally, we reiterate in response to Entergy that the Commission did not intend to 

abrogate existing generator imbalance agreements as a part of this rulemaking 

proceeding.104 The imbalance-related reforms do, however, apply to provisions contained 

in a transmission provider’s OATT, including previously-approved variations from the 

pro forma OATT. Transmission providers were given an opportunity to seek continued 

approval of such previously-approved variations, provided the variations continued to be 

consistent with or superior to the revised pro forma OATT. We note that Entergy made 

such a showing with respect to the generator imbalance provisions of its OATT.105

c. Intentional Deviations and Intra-hour Netting

296. The Commission declined in Order No. 890 to impose generic penalties in the pro 

forma OATT for intentional deviations, concluding that the tiered imbalance penalties 

generally provide a sufficient incentive not to engage in such behavior. The Commission 

explained that proposals to assess additional penalties for intentional deviations would 

 104 See Order No. 890 at P 671. 

105 See Entergy Services, Inc., 120 FERC ¶ 61,042 (2007). 
Docket No. RM05-17-001, et al. - 149 -

continue to be considered on a case-by-case basis, subject to a showing that they are 

necessary under the circumstances. Any such tariff provisions must include clearly 

defined processes for identifying intentional deviations and the associated penalties. 

Requests for Rehearing and Clarification

297. South Carolina E&G argues that the Commission should grant rehearing to assess 

additional penalties for entities that deliberately lean on the system or, in the alternative, 

provide for generator imbalance settlements over a shorter period than one hour. In its 

view, generators unable to ramp up precisely to meet their schedules can under-generate 

in the initial part of the hour and then over-generate in later parts of the hour in order to 

integrate closer to the schedule when settled over the entire hour. South Carolina E&G 

contends that this practice imposes costs on balancing authorities and affects system 

reliability, yet does not necessarily trigger the higher-tiered imbalance charges. South 

Carolina E&G argues that adopting higher penalties for substantial hourly imbalances 

does not address the issue of intra-hour swings, which instead could be resolved by 

adopting 10-minute imbalance charges. 

Commission Determination

298. The Commission denies rehearing of the decision in Order No. 890 not to impose 

generic penalties for intentional deviations. We continue to believe that it is appropriate 

to maintain the status quo of aggregating net generation over the hour in the pro forma

OATT. To the extent a transmission provider wishes to adopt additional penalties for 

intentional deviations, it may do so provided it can show they are necessary under the 

circumstances. As the Commission explained in Order No. 890, requests to adopt a 
Docket No. RM05-17-001, et al. - 150 -

shorter interval over which to calculate imbalances also will be considered on a case-bycase basis, provided that such proposals are consistent with relevant market structures.106 

d. Definition of Incremental Cost

299. In Order No. 890, the Commission defined incremental cost, for purposes of the 

tiered imbalance provisions, 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, purchased and interchange power costs and taxes, as applicable. The 

Commission also concluded that it was appropriate, through the definition of incremental 

cost, to allow for recovery of both commitment and redispatch costs, but excluded on a 

generic basis the cost of additional regulation reserves. The Commission emphasized 

that allowable costs should only be those additional costs incurred by the transmission 

provider due to the imbalance and, if applicable, start-up costs should be allocated pro 

rata to the offending transmission customers based on cost causation principles. 

300. If the transmission provider elects to have separate demand charges to recover the 

cost of holding additional regulation reserves for meeting imbalances, the Commission 

stated that the transmission provider should file a rate schedule and demonstrate that 

these charges do not allow for double recovery of such costs. With regard to the realtime regulation burden imposed by merchant generation, the Commission stated that 

transmission providers could propose, on a case-by-case basis, separate regulation 

 106 See Order No. 890 at P 722. 
Docket No. RM05-17-001, et al. - 151 -

charges for generation resources selling out of the control area. The Commission 

concluded that the other demand costs of providing imbalance service are already 

provided under Schedule 3, 5, and 6 charges. 

Requests for Rehearing and Clarification

301. While generally supporting the Commission’s definition of incremental costs, 

Williams requests that the Commission further identify how each component of the 

transmission provider’s incremental cost is to be determined. In William’s view, a 

specific calculation methodology should be imposed, otherwise the definition of the 

incremental cost will afford transmission providers undue discretion in the calculation of 

imbalance charges. To remove this discretion, Williams suggests that the Commission 

require transmission providers to use the same components and the same methodology 

for the calculation of incremental costs for imbalance charges as the transmission 

provider (or its affiliate) uses to calculate the incremental cost of each resource for 

dispatching generation resources. At a minimum, Williams asks that the Commission 

require transmission providers to post on their OASIS the method used to calculate 

incremental costs for purposes of imbalance charges, along with the method to obtain 

each component or variable in the calculation. 

302. Several petitioners argue that the Commission’s definition of incremental cost for 

purposes of calculating imbalance charges does not properly account for the costs 

actually incurred to provide imbalance energy. 107 Ameren and Southern assert that 

 107 E.g., Ameren, EEI, E.ON U.S., and Southern.
Docket No. RM05-17-001, et al. - 152 -

failure to provide for recovery of opportunity costs will prevent utilities required to serve 

an imbalance from being made whole for forgone opportunities to sell excess energy to 

third parties. Ameren contends that the Commission has determined that not allowing the 

recovery of opportunity costs is inappropriate when the applicable rate is lower than the 

market clearing price.108 Ameren argues that excluding opportunity costs unnecessarily 

harms the transmission provider’s native load customers since the revenues that the 

utilities would have realized from selling their excess energy would have been credited 

back to those customers. Southern and E.ON U.S. ask that the Commission expressly 

provide that incremental costs include opportunity costs, as well as environmental costs, 

capacity charges, dispatch losses and other costs that the transmission provider must bear 

to provide the transmission customer with imbalance service. 

303. Some petitioners argue that it is inappropriate to base the calculation of 

incremental cost on the last 10 MW dispatched to supply the transmission provider’s 

native load.109 EEI argues that, the definition of incremental and decremental cost should 

be determined based on the cost to provide the last 10 MW of energy to serve the 

transmission provider’s native load and all other contractual or franchise obligations, 

including the imbalance service itself. Progress Energy and EEI contend that the 

transmission provider almost always incurs incremental costs per kWh that are higher 

than the incremental costs of serving its native load because native load typically has first 

 108 Citing Xcel Energy Services, Inc., 117 FERC ¶ 61,127 (2006). 

109 See, e.g., Ameren, EEI, MidAmerican, Progress Energy, and Southern. 
Docket No. RM05-17-001, et al. - 153 -

call on least-cost resources. As a result, EEI argues that the Commission’s definition of 

incremental cost transfers to imbalance customers the value of the difference between the 

incremental cost per kWh to serve native load and the incremental cost per kWh to serve 

other contractual commitments, to the detriment of either the transmission provider or its 

native load customers. 

304. MidAmerican argues that the Commission’s definition of incremental cost could 

create an incentive to deliberately under-generate in order to receive the benefit of the 

transmission provider’s least-cost dispatching. To provide appropriate incentives, 

Progress Energy asks that the Commission revise the definition to include the cost of 

providing the last 10 MW of energy to serve the transmission provider’s native load plus 

third party sales, while MidAmerican argues that imbalances charges should be based on 

the incremental cost of the most expensive 10 MW of generation resources in service at 

the time the imbalance occurs. Southern contends that incremental cost should be 

defined based on the next (not the last) 10 MW dispatched. Southern asserts that this 

distinction is especially important in those instances where the cost of the next 10 MW 

will be significantly different than the last 10 MW, such as at the break point requiring 

deployment of a combustion turbine generator. Southern therefore asks that the 

Commission grant rehearing to establish separate definitions for incremental and 

decremental cost and revise the definition of incremental cost so that it is based on the 

next 10 MW dispatched. 

305. EEI and Progress Energy also seek clarification of the definition of, and cost 

recovery for, decremental costs in particular. EEI contends that the definition adopted in 
Docket No. RM05-17-001, et al. - 154 -

Order No. 890 could result in the transmission provider crediting the customer an amount 

that exceeds the costs that the transmission provider actually avoided by accepting excess 

energy. EEI states, for example, that a transmission provider might decrease the output 

of a dispatchable unit in response to an imbalance even though it might also have a 

higher-cost power purchase contract with a fixed amount of energy to be delivered in that 

hour. EEI argues that the Commission’s definition of decremental cost would require the 

transmission provider to pay the imbalance customer based on the higher-cost purchased 

power resource even though it has not avoided those costs as a result of accepting the 

customer’s excess energy. In EEI’s view, decremental cost should be defined to include 

costs that are avoided as a result of receiving imbalance energy. 

306. Progress Energy asks that the definition of decremental cost be clarified to allow 

the recovery of start-up costs that are incurred in an hour different from the hour of 

excess imbalance. Progress Energy contends that requiring a transmission provider to 

accept excessive imbalance energy and could force it to cycle a unit off-line in order to 

accommodate the energy. Progress Energy argues that the later start-up cost for the shutdown unit should be passed along to the imbalance customer, rather than shifted to the 

native load. 

307. Other entities assert the Commission’s definition of incremental cost is 

inappropriate in light of their particular market structure. When a joint dispatch 

agreement exists between the transmission provider and other balancing authorities, 

MidAmerican argues that the joint dispatch incremental or decremental cost should be 

used in place of native load since there is no identification of the transmission provider’s 
Docket No. RM05-17-001, et al. - 155 -

native load other than as part of an aggregated, jointly dispatched load. MidAmerican 

also argues that transmission providers may have little or no native load from which to 

price imbalance costs in retail choice states. NorthWestern agrees that the definition of 

incremental cost fails to consider the circumstances of transmission providers that have 

little or no generation on their system. NorthWestern argues that the Commission should 

have expressly provided additional flexibility for such transmission providers through the 

definition of incremental cost instead of requiring them to file under FPA section 205 for 

acceptance of previously-approved imbalance pricing based on purchased power costs. 

308. Entergy challenges as too narrow the Commission’s decision to consider on a 

case-by-case basis proposals to charge separate regulation charges for generation 

resources selling out of the control area. Entergy states that the generator imbalance 

provisions of its OATT contain both a generator imbalance charge and a generator 

regulation charge, each of which are calculated based on the internal and external 

schedules submitted by independent generators. Entergy argues that this is appropriate 

because, regardless of whether the load is within the control area or outside the control 

area, the generator has a schedule with the control area that is met by control area 

resources. Entergy contends that applying a generation regulation charge only to external 

transactions would be arbitrary. Entergy requests clarification that the generator 

regulation service charges contained in its pro forma Generator Imbalance Agreement, 

which Entergy states was negotiated with generators on its system, continues to be 

acceptable. 
Docket No. RM05-17-001, et al. - 156 -

Commission Determination

309. The Commission grants rehearing of the decision to calculate incremental costs for 

purposes of assessing imbalance charges based on the last 10 MW dispatched to supply 

the transmission provider’s native load. Upon consideration of petitioners’ arguments, 

we agree that it is more reasonable to base imbalance charges on the actual cost to correct 

the imbalance, which may be different than the cost of serving native load. As such, we 

will modify the definition to require transmission providers to use the cost of the last 10 

MWs dispatched for any purpose, i.e., to serve native load, correct imbalances, or to 

make off-system sales. We believe this satisfies Southern’s concerns and therefore 

decline to adopt its suggestion to separately define incremental and decremental cost for 

purposes of calculating imbalance charges by using the “next 10 MW of generation 

dispatched” in the incremental cost definition. 

310. We also agree with Williams that, in order to provide transparency and minimize 

opportunities for undue discrimination, each transmission provider must provide 

language in its OATT clearly specifying the method by which it calculates incremental 

costs for purposes of imbalance charges, as well as the method it will use to obtain each 

component of the calculation. We direct transmission providers to include this proposed 

tariff language as part of the compliance filing ordered in section II.C. 

311. Several entities complain that the Commission’s definition of incremental cost 

does not properly allow for recovery of opportunity costs. The determination and 

calculation of opportunity costs associated with providing imbalance service will vary 

based on the circumstances of the transmission provider and, as such, we do not believe 
Docket No. RM05-17-001, et al. - 157 -

that it is appropriate to amend the definition of incremental cost in the pro forma OATT 

to address opportunity costs. We will therefore continue to consider proposals to include 

recovery of legitimate and verifiable opportunity costs on a case-by-case basis consistent 

with Commission precedent.110 Such proposals must clearly explain how opportunity 

costs would be determined and demonstrate that the recovery of opportunity costs would 

not lead to over-recovery of costs. Similarly, transmission providers participating in joint 

dispatch agreements or otherwise procuring imbalance energy from other generators may 

need to have alternative definitions of incremental cost. Proposals to adopt a modified 

definition of incremental cost to reflect the transmission provider’s particular 

circumstances also will be considered on a case-by-case basis. 

312. With regard to the definition of incremental cost in particular, we clarify that 

transmission providers can include in the calculation of incremental cost start-up costs 

that are incurred in an hour different from the hour of excess imbalance, provided that the 

costs are in fact associated with providing imbalance service. We disagree with EEI with 

respect to its description of incremental costs. The fixed amount power purchase contract 

in EEI’s example should not be used in calculating incremental costs because it would 

not be included in the last 10 MW of generation dispatched by the transmission provider. 

In the case that a transmission provider is ramping down generation in an hour, the 

additional costs of the last 10 MW dispatched by the transmission provider should be 

used in calculating incremental costs for the purpose of financially settling imbalances. 

 110 See Order No. 888 at 31,740. 
Docket No. RM05-17-001, et al. - 158 -

313. In response to Entergy, we clarify that transmission providers may propose to 

assess regulation charges to generators selling in the control area, as well as generators 

selling outside the control area, and that the Commission will consider such proposals on 

a case-by-case basis, as we have in the case of Entergy’s pro forma Generator Imbalance 

Agreement. In accordance with the procedures established in Order No. 890, Entergy 

sought continued approval of its generator imbalance provisions, including the 

assessment of generator regulation charges. The Commission accepted this variation as 

consistent with or superior to the pro forma OATT, based on the particular circumstances 

presented by Entergy.111 We will continue to consider requests to assess regulation 

charges on generators on a case-by-case basis upon consideration of the facts and 

circumstances presented. 

e. Inadvertent Energy Treatment 

314. The Commission found in Order No. 890 that inadvertent energy is not 

comparable to energy and generator imbalances and, therefore, allowed inadvertent 

energy to be treated differently from imbalances. The Commission explained that 

variables affecting inadvertent interchange often depend on the actions or the omissions 

of utilities other than the individual transmission providers and are distinct from those 

resulting in energy and generator imbalances. The Commission concluded that the 

historic practice of paying back inadvertent interchange in kind has not proven to have 

adverse effects on reliability. 

 111 See Entergy Services, Inc., 120 FERC ¶ 61,042 at P 66 (2007). 
Docket No. RM05-17-001, et al. - 159 -

Requests for Rehearing and Clarification

315. TDU Systems contend that the Commission’s acceptance of in-kind compensation 

for interchange energy undermines its rejection of requests to allow transmission 

customers to address monthly imbalances with in-kind transfers. TDU Systems argue 

that there is no evidentiary basis for the Commission to conclude that transmission 

providers have little control over the causes of system imbalances. TDU Systems state 

that transmission providers typically control 80-90 percent of the load on their systems 

and the dispatch of resources to serve that load. In TDU Systems’ view, both 

transmission provider and transmission customer imbalances result from circumstances 

beyond their control, namely: telemetry failure, meter error, generator governor response 

to system problems, human error, uncontrollable load forecast errors due to rapidly 

changing weather, and under- or over-supply of generation. 

316. TDU Systems state that deviations between load and supply, whether in the form 

of energy imbalances or inadvertent energy, each require adjustment or compensation and 

that there is no reason why that adjustment or compensation should be different among 

transmission users. TDU Systems argue that failure to allow for in-kind payment for 

imbalances within the month provides a competitive advantage to transmission providers 

and constitutes undue discrimination in violation of the FPA. In their view, the 

Commission remedied this discrimination within RTOs by requiring in Order No. 2000 
Docket No. RM05-17-001, et al. - 160 -

that the same imbalance rules apply to transmission users and control area operators.112 

TDU Systems argues that the Commission fails to explain its departure from its 

resolution of this issue in the RTO context and that it is irrelevant that transmission 

providers may have historically paid back inadvertent interchanges with in-kind transfers 

without problem. 

Commission Determination

317. The Commission denies rehearing of the decision in Order No. 890 to allow 

inadvertent energy to be treated differently from energy and generator imbalances. As 

the Commission explained in Order No. 890, inadvertent energy is not comparable to 

energy and generation imbalances and the variables affecting each are distinct. It is 

therefore appropriate to treat inadvertent energy and imbalances differently 

notwithstanding the fact that both inadvertent exchanges and imbalances may be beyond 

the control of the transmission provider or customer, respectively. 

318. Our primary concern with respect to inadvertent energy continues to be avoidance 

of incentives that could degrade reliability. To date, the return-in-kind approach to 

inadvertent energy has proven adequate as a general matter. Petitioners do not present 

any evidence that in-kind payment of inadvertent energy is no longer sufficient to 

maintain reliability or allows certain entities to lean on the grid to the detriment of other 

 112 Citing Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 

6, 2000), FERC Stats. & Regs. ¶ 31,089 at 31,142 (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). 
Docket No. RM05-17-001, et al. - 161 -

entities. We disagree that this treatment of inadvertent energy is inconsistent with Order 

No. 2000. There the Commission required both control area operators and transmission 

customers within an RTO to clear imbalances through a real-time balancing market.113 In 

the absence of a real-time balancing market, we continue to believe it is appropriate for 

transmission providers operating under the pro forma OATT to treat inadvertent 

interchange differently than customer imbalances. 

f. Netting of Energy and Generator Imbalances

319. In Order No. 890, the Commission concluded that it is not appropriate to require 

transmission providers to allow netting of generator and energy imbalances outside of the 

tier one band. While the Commission recognized that allowing transmission customers to 

net energy and generator imbalances would have competitive benefits and enhance 

comparability, the Commission determined that it could lessen the incentive for accurate 

scheduling and, in turn, increase imbalances that create reliability or economic issues for 

specific areas of the system. 

Requests for Rehearing and Clarification

320. Several petitioners ask that the Commission clarify that netting and settling within 

the first deviation band should be done on a financial basis, based on hourly incremental 

and decremental costs, rather than netting imbalances on the basis of megawatt-hours of 

imbalance and settling the net imbalance on a financial basis.114 EEI, MidAmerican and 

 113 See Order No. 2000 at 31,142. 

114 E.g., EEI, MidAmerican, Southern, Progress Energy, and Entergy. 
Docket No. RM05-17-001, et al. - 162 -

Progress Energy assert that otherwise customers would be able to offset energy shortfalls 

in on-peak, high-cost periods against excess energy in off-peak, lower-cost hours, which 

would inappropriately shift costs to native load customers. If imbalances are netted based 

on megawatt-hours prior to financial settlement, EEI and Progress Energy argue that it 

would be impossible to calculate charges for net imbalances at the end of the month 

because the transmission provider would not be able to correlate monthly net imbalances 

with hourly incremental and decremental costs without exercising subjective judgment. 

Southern and EEI contend that the Commission, at a minimum, should require the 

imbalances to be netted separately for on-peak periods and off-peak periods if it 

determines that imbalances should be netted on a megawatt-hour basis. EEI suggests that 

the price for net first tier imbalances then be based on each month’s average incremental 

and decremental costs, calculated separately for on-peak periods and off-peak periods. 

321. Other petitioners assert that the Commission should allow netting outside of the 

first tier band.115 Ameren argues that the threshold of the first tier band is unnecessarily 

low, suggesting it would be more appropriate to allow imbalances of less than 10 MW to 

be netted. For imbalances from 10 MW up to as much as 50 MW, Ameren suggests that 

the Commission allow netting of imbalances equal to the greater of 10 MW or 50 percent 

of its scheduled amount. TDU Systems argue that transmission customers should be 

allowed to net all imbalances across the transmission system within a month, reflecting 

appropriate differences for imbalances incurred during peak and off-peak hours. TDU 

 115 E.g., TAPS, Ameren, and TDU Systems. 
Docket No. RM05-17-001, et al. - 163 -

Systems contend that netting should be unrestricted within the month so long as the 

results keep the transmission provider economically whole. TDU Systems argue that 

there is no evidence that netting creates reliability problems and that limiting netting is 

not comparable to the transmission provider’s treatment of imbalances of its retail native 

load, generation affiliates, and marketing affiliates. TDU Systems also argue that 

restricting netting within the month is an unexplained departure from the Commission’s 

treatment of natural gas pipeline imbalances. 

322. NRECA asks the Commission to confirm, either on clarification or rehearing, that 

separate imbalance charges may not be assessed on each of a customer’s separate 

transactions on an interface or within a control area in a single hour. NRECA contends 

that a customer’s contribution to area control error (ACE) on a given interface is no more 

than the aggregate difference between schedules and deliveries and, therefore, its impact 

on the balance of resources and loads within a control area is no more than the aggregate 

difference between its resources’ output and its load. If a transmission provider’s system 

is so underdeveloped that constraints prevent transactions sourcing at different locations 

within the control area from being treated comparably, the Commission should require 

the transmission provider to upgrade its system rather than penalize the customer with 

multiple sets of imbalance charges on separate transactions. 

Commission Determination

323. The Commission affirms the decision in Order No. 890 to allow netting of 

imbalances within the first tier deviation band. As the Commission explained in Order 

No. 890, there is a tradeoff between allowing customers to net imbalances, which would 
Docket No. RM05-17-001, et al. - 164 -

enhance comparability between the transmission provider’s dispatch and the customers 

serving load, and the need to create incentives to limit customer imbalances due to the 

reliability or economic issues they can cause for specific areas of the system.116 Netting 

can cause problems because it lessens the incentive for transmission customers to 

schedule accurately and inaccurate schedules, in turn, can require actions by the 

transmission provider even when imbalances offset. We believe the Commission struck 

the appropriate balance in Order No. 890 between the customer’s need for flexibility and 

the transmission provider’s need for accuracy and, therefore, deny TDU Systems’ request 

to require netting of imbalances outside the tier one band and Ameren’s related request to 

expand the tier one band for purposes of netting. 

324. We also deny NRECA’s request that separate imbalance charges not be assessed 

on each of a customer’s separate transactions on an interface or within a control area in a 

single hour. Where transmission constraints exist, a customer whose load and generation 

was on net equal could still have an effect on the transmission system if some generation 

is ramping up to respond to some imbalances while other generation is ramping down 

exactly at the same time. We disagree with TDU Systems that our decision is an 

unexplained departure from the Commission’s treatment of natural gas pipeline 

imbalances. Natural gas pipelines frequently have opportunities to use storage and line 

pack to absorb day-to-day imbalances. Individual pipelines have tailored their imbalance 

requirements, including penalty provisions as needed, to meet their specific 

 116 See Order No. 890 at P 715. 
Docket No. RM05-17-001, et al. - 165 -

circumstances. The transmission of electricity, in contrast to the transportation of natural 

gas, requires instantaneous balancing which makes the need for imbalance provisions on 

a shorter-term basis important for the protection of reliability. NERC has created 

standards such that each control area is responsible for managing its Area Control Error 

and operating within line limits in order to protect reliability. Imbalances created by 

transmission customers impose an additional burden on the transmission provider to 

manage imbalances within the hour (as well as shorter time periods) justifying a different 

tariff approach under the pro forma OATT. As such, the imbalances provisions adopted 

in the pro forma OATT are used to protect reliability during the applicable time period. 

325. With regard to netting within the tier one band, we clarify that netting should be 

done on a megawatt-hour basis, rolling over the month. Imbalances remaining at the end 

of the month should be settled at the load weighted average of the hourly incremental 

costs during that month.117 We decline to require that imbalances be netted separately for 

on-peak and off-peak periods. Netting only applies to imbalances within the tier one 

band, which are relatively minor and largely within the normal range of uncertainty that 

cannot be avoided even under optimal operating conditions. We therefore disagree that it 

is necessary to adopt a more granular imbalance pricing mechanism when netting 

imbalances within the first tier. However, if a transmission provider finds that its 

 117 For example, if a generator had 5 imbalances within the first deviation band in 

a month of +2 MWh, -6 MWh, +4 MWh, -2 MWh, -1 MWh, the net MWh imbalance for 

the generator at the end of the month would be -3 MWh. The generator would pay the 

transmission provider for 3 MWh at the load weighted average of the hourly incremental 

costs during that month. 
Docket No. RM05-17-001, et al. - 166 -

customers are arbitraging on-peak and off-peak prices within the first tier, it may propose 

a more granular approach to netting subject to a showing that it is necessary under the 

circumstances. 

g. Distribution of Penalty Revenues above Incremental Cost

326. With regard to revenues received through imbalance charges, the Commission 

required transmission providers to develop a mechanism for crediting such revenues to all 

non-offending transmission customers, including affiliated transmission customers, and 

the transmission provider on behalf of its own customers. The Commission concluded 

that such distribution of revenues recognizes that transmission providers bear the 

responsibility to correct imbalances and often use their own facilities to do so. 

Requests for Rehearing and Clarification

327. Ameren contends that the transmission provider should be allowed to keep all the 

penalty revenues associated with correcting imbalances and that development of a credit 

mechanism imposes an unnecessary and unwarranted administrative burden on 

transmission providers. Ameren argues that the transmission provider should receive any 

amounts above its incremental costs of providing imbalance service as a contribution 

towards the fixed costs of providing this service and that any revenues from penalties 

assessed on customers for leaning on the system should be credited to long-term firm 

transmission customers. 

328. TDU Systems, however, object to the Commission’s decision to allow 

transmission providers to retain a portion of the imbalance penalty revenues for their own 

retail customers. TDU Systems contend that transmission providers do not pay 
Docket No. RM05-17-001, et al. - 167 -

imbalance penalties when they over- or under-schedule their loads and, thus, receipt of 

related penalty revenues by transmission providers would constitute a windfall. TDU 

Systems argue that the Commission failed to explain its departure from Carolina Power 

& Light118 because the Commission’s decision in that case to deny credits to CP&L on 

behalf of its retail customers was based on those customers not being subject to energy 

imbalance penalties in the first place. TDU Systems contend that this fundamental 

paradigm has not changed with reform of the OATT. 

329. MidAmerican requests clarification that it is appropriate to propose its imbalance 

penalty distribution mechanism in the compliance filing containing the non-rate terms 

and conditions of the pro forma OATT. Joined by NorthWestern and Mark Lively, 

MidAmerican also requests guidance as to the particular information the Commission 

would require in those filings with regard to the penalty distribution mechanism. 

NorthWestern asks the Commission to specify how the transmission provider should 

determine what customers are non-offending and over what period of time. Mark Lively 

seeks clarification of the time frame during which there is to be a matching of penalty 

revenue and credits to non-offending customers. If the matching is done on a monthly 

basis, Mark Lively contends that most if not all transmission customers will be found to 

be offending at some time during the month and thus not be eligible to be in the class of 

customers to receive a credit for part of the penalty revenue collected by the transmission 

provider. Mark Lively suggests an alternative crediting mechanism to synchronize 

 118 103 FERC ¶ 61,209 (2003) (CP&L). 
Docket No. RM05-17-001, et al. - 168 -

penalties and credits by having the variance from full incremental cost be uniform for any 

hour or any intra-hour period, with revenues from over-deliveries shared with nonoffending load and revenues from under-deliveries shared with non-offending supply. 

330. NorthWestern also asks the Commission to expressly confirm that the 

transmission provider is not required to distribute penalty revenues until after it recovers 

all costs (including any associated transmission costs) incurred in providing imbalance 

service. NorthWestern contends that the market for such services is limited and, as a 

result, it has had to contract with entities located outside its control area for system 

balancing and load following services in order to provide imbalance service. 

Commission Determination

331. The Commission affirms the decision in Order No. 890 to require transmission 

providers to credit revenues from imbalance charges in excess of incremental costs to all 

non-offending customers, including affiliates, and the transmission provider on behalf of 

its retail customers. As the Commission explained in Order No. 890, transmission 

providers with significant imbalance penalties have been required in the past to develop a 

mechanism to credit penalty revenues to non-offending transmission customers.119 We 

disagree with Ameren that this imposes an unreasonable administrative burden on 

transmission providers. We note that Ameren did not seek rehearing of the decision to 

require transmission providers to develop a similar mechanism to distribute unreserved 

 119 See Order No. 890 at P 727 (citing CP&L, 103 FERC ¶ 61,209 at P 25; Entergy 

Services, Inc., 105 FERC ¶ 61,319 (2003), reh’g denied, 109 FERC ¶ 61,095 (2004)). 
Docket No. RM05-17-001, et al. - 169 -

use penalties to non-offending customers, discussed in section III.C.4.b.120 We would not 

expect development of that distribution mechanism to be any more burdensome than 

distributions of imbalance penalty revenues. 

332. We also disagree with TDU Systems that the transmission provider on behalf of its 

native load customers should be excluded from the distribution of imbalance revenues. 

Transmission providers bear the responsibility to correct imbalances, often using their 

own facilities to do so, and thus their receipt of imbalance revenues does not constitute a 

windfall. While it is true that the Commission in CP&L considered relevant the fact that 

CP&L’s customers were not subject to imbalance charges, the Commission expressly 

rejected CP&L’s proposal to retain revenues because it would have been “contrary to the 

Commission’s objective to eliminate incentives for transmission providers to use 

penalties as a profit center.”121 The imbalance charges adopted in Order No. 890 more 

closely relate to incremental cost and therefore minimize any incentive on the part of the 

transmission provider to rely on penalty revenues rather than seeking other methods of 

encouraging accurate scheduling. Under these circumstances, there remains no reason to 

exclude the transmission provider from receiving an appropriate share of penalty 

revenues. 

333. Regarding the time frame during which there is to be a matching of penalty 

revenue and credits to non-offending customers, we clarify that the transmission provider 

 120 See id. at P 860-61. 

121 CP&L, 103 FERC ¶ 61,209 at P 26. 
Docket No. RM05-17-001, et al. - 170 -

should distribute the penalty revenue received in a given hour to those non-offending 

customers in that hour, i.e., those customers to whom the penalty component did not 

apply in the hour. Customers that were out of balance, but within the first tier, should 

therefore be included in the distribution. Since most transmission customers will be out 

of the first deviation band at some hour during the month, we agree that it would not be 

appropriate to exclude these customers from receiving a pro rata portion of penalty 

revenues in the other hours. In response to NorthWestern, we clarify that the 

transmission provider, as part of its distribution methodology, may address how 

distributions may be affected by the transmission provider’s inability to recover the costs 

incurred to provide imbalance service. 

2. Credits for Network Customers

a. Severance of Credits and Planning

334. In Order No. 890, the Commission adopted the NOPR proposal to sever the link in 

the pro forma OATT between joint planning and credits for new facilities owned by 

network customers. The Commission concluded that linking credits for new facilities to 

a joint planning requirement can act as a disincentive to coordinated planning, which is 

contrary to the Commission’s original objective in adopting the provision. The 

Commission also concluded that the coordinated planning initiatives adopted in Order 

No. 890 will ensure that most, if not all, transmission facilities are planned on a 

coordinated basis, notwithstanding the severance of the link between credits for new 

facilities and joint planning. 
Docket No. RM05-17-001, et al. - 171 -

 Requests for Rehearing and Clarification 

335. E.ON U.S. argues on rehearing that the Commission failed to adequately address 

comments suggesting that severing the link will excuse network customers from 

participating in the joint planning process and permit a network customer to build 

facilities without oversight or input from a transmission provider. While Order No. 890 

places an affirmative burden on the transmission provider to coordinate long-term 

transmission planning, E.ON U.S. states that no corresponding obligation is placed on the 

transmission customer. E.ON U.S. argues that transmission service credits for facilities 

constructed by network customers should be available only when the facility is jointly 

planned with the transmission provider. 

336. NorthWestern agrees, arguing that if a network customer is permitted to construct 

facilities and later declare them to be worthy of a credit, such facilities will not serve the 

overall grid as efficiently as jointly planned facilities. NorthWestern also argues that 

severing the link will lead to protracted litigation regarding what facilities qualify for 

credits. To ensure efficient coordination of facility planning, NorthWestern requests that 

the Commission reconsider its decision to sever joint planning and transmission service 

credits. 

 Commission Determination

337. E.ON U.S. and NorthWestern both argue that, by severing the link between joint 

planning and credits for network customers, the Commission is sacrificing the benefits 

that resulted when a transmission provider made credits available as part of its centralized 

planning process. We disagree. As the Commission explained in Order No. 890, the 
Docket No. RM05-17-001, et al. - 172 -

linkage between credits and joint planning gave the transmission provider an incentive to 

deny coordinated planning to avoid granting credits for customer-owned facilities.122 

Therefore, it was necessary to sever the link between credits and joint planning. Any 

efficiencies that may be lost by severing that link should be offset by the increased 

efficiencies resulting from the coordinated planning initiative required in Order No. 890, 

which the Commission noted will ensure that most, if not all, transmission facilities are 

planned on a coordinated basis.123 With the clarifications provided below, we do not 

expect that severing the link between joint planning and credits will lead to unnecessary 

litigation. 

b. The New Test to Determine Eligibility for Credits

338. In Order No. 890, the Commission declined to adopt the credits test for new 

facilities proposed in the NOPR and, instead, revised the test to more accurately reflect 

the Commission’s intent as expressed in the NOPR. A transmission customer is required 

to meet the integration standard under pro forma OATT section 30.9 to receive a credit 

for its facilities. Under the integration standard, the customer must demonstrate that its 

facilities not only are integrated with the transmission provider’s system, but also provide 

additional benefits to the transmission grid in terms of capability and reliability and can 

 122 See Order No. 890 at P 735. 

123 See id. at P 736. 
Docket No. RM05-17-001, et al. - 173 -

be relied on by the transmission provider for the coordinated operation of the grid.124 

Because joint planning will no longer be required to obtain credits, the Commission noted 

that it is particularly important in this context to require a showing that a network 

customer’s facilities provide benefits to the transmission provider’s grid. To ensure 

comparability, the Commission adopted the presumption of integration for transmission 

customer facilities that, if owned by the transmission provider, would be eligible for 

inclusion in the transmission provider’s annual transmission revenue requirement as 

specified in Attachment H of the pro forma OATT. 

 Requests for Rehearing and Clarification

339. NRECA, TAPS and the TDU Systems request that the Commission confirm that 

the integration requirement under Order No. 890 does not require a more stringent 

standard for network customer facilities than for transmission provider facilities or in any 

way compromise the language in section 30.9 of the pro forma OATT. NRECA argues 

that the language in Paragraph 754 of Order No. 890 and, in particular the affirmation of 

the “benefits to the grid” test in footnote 436, contradict section 30.9 by establishing an 

explicitly different and harder test for transmission customer facilities than for 

transmission provider facilities. Other petitioners agree,125 requesting that the 

Commission explain that it did not intend to impose the “additional benefits to the grid” 

 124 See id. at P 754, n.436 (citing Southwest Power Pool, Inc., 108 FERC ¶ 61,078 

(2004), reh’g denied, 114 FERC ¶ 61,028 (2006)). 

125 E.g., TAPS and TDU Systems. 
Docket No. RM05-17-001, et al. - 174 -

and “relied on by the transmission provider” criteria (which they state are not required for 

a transmission provider’s facilities) on a network customer’s facilities. 

340. Several petitioners argue that an integration standard requiring the showing of 

benefits to the grid is unduly discriminatory because it maintains the presumption that a 

transmission provider’s transmission facilities provide benefits while requiring a network 

customer to make an affirmative showing that its facilities provide benefits to qualify for 

credits.126 FMPA and TDU Systems argue that comparability requires the same 

presumption of integration to be applied to all transmission facilities. To provide 

certainty for those building new infrastructure, TDU Systems contend that the 

Commission should require transmission providers to credit third parties for the costs of 

new facilities in a manner comparable to the compensation provided for a transmission 

provider’s comparable facilities. 

341. APPA contends that the presumption of integration is confusing because it is 

unclear how a network customer would make a showing that facilities would be eligible 

for inclusion in a transmission provider’s revenue requirement if owned by the 

transmission provider or what the specific legal effect would be if the network customer 

succeeded in making such showing. APPA suggests that the Commission require credits 

if the customer can show that the transmission provider includes in its own revenue 

requirement or gives credits to other customers for facilities similar to those for which the 

networks customer seeks credits. 

 126 E.g., APPA, FMPA, NRECA and TAPS. 
Docket No. RM05-17-001, et al. - 175 -

342. In implementing the presumption of integration to obtain credits, TAPS and APPA 

maintain that the Commission cannot require a network customer to show more than that 

its facilities are comparable to similar facilities the transmission provider actually 

includes in its rate base. TAPS argues that the Commission should clarify that the 

presumption cannot be overcome by evidence that the transmission provider and the 

transmission provider’s other customers do not use or directly benefit from the customerowned facilities. TAPS therefore requests that the Commission make clear that it will not 

follow precedents developed in credit cases decided under the original OATT section 

30.9 regarding the types of “benefits” provided by a customer’s facilities. Specifically, 

TAPS argues that a network customer of a transmission provider that includes the cost of 

facilities (including radials) that are used solely to serve the transmission provider’s retail 

customers must be able to use the Order No. 890’s presumption to obtain credits for 

similar facilities that serve only that transmission customer’s retail customers. 

343. FMPA also oppose any implementation of the Commission’s integration test that 

treats customers and transmission providers differently. FMPA argue that, if a customer’s 

facilities are necessary to serve the customer’s load, the customer should be provided a 

credit since the transmission provider includes in rate base the cost of its facilities used to 

serve load. In their view, the same presumption of integration applies to all transmission 

facilities, i.e., that transmission is integrated when, if owned by the transmission provider, 

it would be includable in rate base. FMPA cite legislative history and the court’s decision 
Docket No. RM05-17-001, et al. - 176 -

in TAPS v. FERC127 in support of their argument that the comparability principle is central 

to the issue of cost recognition for customer facilities. FMPA contend that recognizing 

their members’ transmission through credits is beneficial because it involves all owners in 

joint planning and the exchange of information that results in grid construction and 

operation that will better serve the needs of all consumers. Without this role in joint 

planning, less reliable transmission and fewer generation and power supply options for 

systems will result. In addition, if credits are denied, FMPA will be inhibited from 

contributing necessary capital to the grid and likely result in reduced public support for 

transmission construction. 

344. Other petitioners contend that the Commission should eliminate any presumption 

that a network customer is entitled to credits, arguing that the presumption violates the 

cost-causation principle by shifting costs to customers for whom the facilities were not 

planned and who are not benefited by their use.128 These petitioners contend that a 

network customer’s facilities are not planned around the needs of the transmission 

provider to meet its obligations and many customer facilities are designed only to pick up 

power from the transmission provider’s grid and deliver it to that network customer’s 

distribution network.129 These petitioners request that the Commission allow for credits 

 127 225 F.3d 667, 681 (D.C. Cir. 2000), aff’d sub nom., New York v. FERC, 535 

U.S. 1 (2002). 

128 E.g., Entergy and Florida Power. 

129 E.g., Entergy, Florida Power and South Carolina E&G. 
Docket No. RM05-17-001, et al. - 177 -

only when the customer’s facilities provide a benefit to the transmission provider’s grid, 

i.e., when the transmission provider relies on a network customer’s facility to serve the 

transmission provider’s transmission customers (including the network customer seeking 

credits) or the transmission provider’s retail customers. They argue that there is no basis 

to presume integration simply because the transmission provider would include the cost 

of such facilities were it the owner. 

345. South Carolina E&G argues a presumption of integration will encourage customer 

overbuilding paid for by a transmission provider’s native load customers. South Carolina 

E&G asks that the Commission confirm that it is not departing from the decade-old twopart test for credits for customer-owned facilities that requires that the facilities are both 

integrated into the network grid and provide benefits to the grid. South Carolina E&G 

disagrees that any revision to that test is required by comparability. In its view, 

customer-owned facilities are not comparable to transmission provider-owned facilities 

for purposes of credit eligibility, since each are built for different purposes and are 

subject to different regulatory oversight. 

346. Florida Power argues that the application of the rebuttable presumption may 

impact reliability. Florida Power contends that, under the new test for credits, a 

transmission provider must show that it does not need the network customer’s facilities to 

provide transmission service to any other customer in order to deny credits. Florida 

Power states that this could result in a network customer being denied credits for a 

facility even if the transmission provider needs the facility to reliably serve the network 

customer. 
Docket No. RM05-17-001, et al. - 178 -

347. Entergy and Florida Power also request that the Commission change its policy of 

applying a stricter standard to a transmission provider’s own facilities when a network 

customer has been denied credits. These petitioners state that, when the Commission 

denies credits for customer-owned facilities, it applies the same integration test to the 

transmission provider’s facilities as that applied to the network customer’s facilities. The 

petitioners argue that application of the integration test to the transmission provider’s 

facilities in that instance is unreasonable since the nature of those facilities does not 

change. They argue that different tests for transmission providers and network customer 

systems are appropriate since each are planned for and used differently. In their view, 

concerns about comparability can be addressed by allowing a transmission provider’s 

looped facility to be rolled into rate base only if the transmission provider uses the 

facility to serve a transmission customer or the transmission customer’s retail customers. 

348. Entergy and Florida Power further claim that the Commission’s approach is 

inconsistent with the treatment of generator interconnections because the Commission’s 

policy entitling an interconnecting generator to credits against transmission charges does 

not change simply because the Commission has denied a network customer credits. 

These petitioners contend that an interconnecting generator could be entitled to credits 

when at the same time the transmission provider could be prohibited from rolling the 

costs of those credits into its rates. 

 Commission Determination 

349. The Commission denies rehearing of the decision in Order No. 890 to modify the 

credits test for new customer-owned facilities. In Order No. 890, the Commission 
Docket No. RM05-17-001, et al. - 179 -

explained that it was retaining the existing integration standard, but adopting a new 

presumption of integration for customer-owned facilities that would be included in rate 

base if owned by the transmission provider.130 The integration standard to be applied to 

new facilities under section 30.9 therefore remains unchanged, so Commission precedent 

regarding application of the standard will continue to apply. Specifically, to satisfy the 

integration standard set forth in section 30.9 of the pro forma OATT, it must be shown 

that a new facility is integrated with a transmission provider’s system, provides additional 

benefits to the transmission grid in terms of capability and reliability, and can be relied on 

by the transmission provider for the coordinated operation of the grid.131 However, in 

recognition of the new requirement for transmission providers to plan their system on an 

open and coordinated basis, a customer’s transmission facilities will be presumed to be 

integrated if the facilities, if owned by the transmission provider, would be eligible for 

inclusion in the transmission provider’s annual transmission revenue requirement as 

specified in Attachment H of the pro forma OATT. 

350. The adoption of this presumption is necessary to ensure comparability between 

network customers and transmission providers serving native load. It is reasonable to 

presume, without application of any particular standard or test, that the transmission 

provider’s facilities benefit the network because they are planned, constructed and 

 130 Order No. 890 at P 753-754. 

131 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). 
Docket No. RM05-17-001, et al. - 180 -

owned, from the beginning, by the transmission provider to meet its obligations to its 

customers. In comparison, because customer-owned facilities are generally constructed 

to serve that individual customer’s needs, the Commission requires the customer to 

satisfy the integration standard in order to qualify for credits. The Commission 

concluded in Order No. 890 that it is now reasonable to presume that any new customerowned facilities satisfy the integration standard, to the extent they would be included in 

the transmission provider’s revenue requirement if they were owned by the transmission 

provider, in light of the requirement imposed on transmission providers to implement an 

open and coordinated transmission planning process that applies to all transmission 

facilities. 

351. To the extent necessary, we clarify that these presumptions of integration are 

rebuttable both as applied to the transmission provider and the network customer. For the 

network customers’ facilities, transmission providers may challenge the presumption that 

the customer’s facilities are integrated by showing they do not actually meet the 

integration standard, notwithstanding the fact that they are similar to facilities in the 

transmission provider’s rate base. Similarly, the presumption that a transmission 

provider’s facilities benefit the network could be overcome by a showing that the 

facilities, in fact, do not provide such benefit. By allowing the presumptions of 

integration to be rebutted, the Commission will ensure that only the costs of facilities that 

are actually part of the integrated network that serves all customers will receive credits. 

It also serves as an incentive for the transmission provider to give credits to network 
Docket No. RM05-17-001, et al. - 181 -

customers that own integrated facilities and remove from its rate base its own nonintegrated facilities. 

352. In light of the modifications to the credits test adopted in Order No. 890, we 

further clarify that denial of credits for a network customer no longer triggers a need for 

the transmission provider to demonstrate that its own facilities satisfy the integration 

standard, because credits for network customer facilities can now be denied only after an 

affirmative showing by the transmission provider that its facilities are not similar under 

the integration test to those of the network customer (i.e., by overcoming the presumption 

of integration). This approach departs from the approach adopted in FP&L,

132 but 

reflects the fact that the new rebuttable presumption in favor of the transmission customer 

has shifted the burden to the transmission provider to provide evidence that credits for the 

customer are not warranted. 

353. To provide clarity regarding how to implement the presumption that a network 

customer’s facilities are integrated, we make clear that a network customer may justify 

application of the presumption by reference to the existing facilities in the transmission 

provider’s rates. A customer need only show that its new facilities are similar in design 

and purpose to facilities owned by the transmission provider that are included in rates. A 

transmission provider may overcome the network customer’s presumed integration by 

 132 Florida Mun. Power Agency v. Florida Power and Light Co., 74 FERC ¶ 

61,006 at 61,010 (1996) (finding that the integration of facilities into the plans or 

operations of a transmitting utility is the proper test for cost recognition), reh’g denied, 

96 FERC ¶ 61,130 at 61,544-45 (2001), aff’d sub nom. Florida Mun. Power Agency v. 

FERC, 315 F.3d 362 (D.C. Cir. 2003). 
Docket No. RM05-17-001, et al. - 182 -

demonstrating, with reference to its own facilities that meet the integration standard, that 

the network customer’s new facilities do not meet the standard. To the extent there are 

disputes regarding whether a customer’s new facilities are sufficiently similar to those in 

the transmission provider’s rate base, we encourage transmission providers and 

customers to resolve those disputes informally or with the assistance of the Commission’s 

Dispute Resolution Service. 

354. We reject requests to eliminate the presumption of integration for new customerowned facilities, as advocated by certain transmission providers. The planning-related 

reforms adopted in Order No. 890 will ensure that a process exists to jointly plan all 

transmission facilities, including new facilities developed by customers. Comparability 

requires that transmission providers and customers alike benefit from a presumption of 

integration. It is also appropriate for both the transmission provider and its customers to 

be subject to the integration standard to the extent the presumption of integration is 

overcome, notwithstanding any coordinated planning of those facilities. Under Order No. 

890, the Commission therefore will not apply, as some petitioners imply, a different or 

stricter standard to a transmission provider’s own facilities when a network customer has 

been denied credits. 

355. We disagree with claims that a presumption of credits for certain customer-owned 

facilities will encourage over-building or harm reliability. Facilities owned by 

transmission providers have long enjoyed a presumption of integration, yet petitioners do 

not object to the presumption as applied to those facilities. Petitioners offer no reason to 

believe that application of a comparable presumption for new customer-owner facilities 
Docket No. RM05-17-001, et al. - 183 -

would lead to reliability or operational difficulties, particularly in light of the obligation 

for transmission providers under Order No. 890 to plan their transmission systems on an 

open and coordinated basis.133 We also believe that it is unlikely that a transmission 

provider would be required to provide credits to an interconnecting generator, but be 

prohibited from rolling the same credits into its rates. Nevertheless, should any such 

circumstance arise, the transmission provider should bring the issue to the Commission’s 

attention for resolution. 

c. Application of the New Test to Existing Facilities

356. In Order No. 890, the Commission concluded that the new test for determining 

credits will apply only to transmission facilities added subsequent to the effective date of 

Order No. 890. The Commission found that there is no reason to revisit the 

determinations with respect to the number of customer-owned transmission facilities that 

have been developed, and resulted in credits negotiated and litigated, under the prior test 

that the Commission determined to be just and reasonable at the time.134 On a 

prospective basis, however, given the increased planning and coordination required in 

Order No. 890, the Commission stated that it is appropriate to apply the new test for 

determining credits. 

 133 As we discuss in section III.B, planning activities must be open to all 

customers, who must provide information regarding expected uses of the system so that 

the transmission provider can plan for their needs. 

134 See East Texas Electric Coop., Inc. v. Central and South West Services, Inc., 

114 FERC ¶ 61,027 (2006). 
Docket No. RM05-17-001, et al. - 184 -

 Requests for Rehearing and Clarification

357. Several petitioners contend that it is inappropriate for the Commission to conclude 

that the newly announced test for determining credits under OATT section 30.9 will 

apply only to transmission facilities added subsequent to the effective date of Order No. 

890, arguing that the Commission should remedy past undue discrimination against 

network service customers such as the failure of transmission providers to jointly plan 

facilities with transmission customers.135 APPA also asks that the Commission explain 

why this result is legally appropriate. 

358. NRECA contends that the Commission should apply the new test for transmission 

credits to both existing and new facilities, but clarify that existing credit agreements or 

determinations will not be impacted. NRECA argues that Mobile-Sierra concerns can be 

avoided by applying the new test to facilities that are built but not yet the subject of a 

credits agreement or determination. APPA suggests that allowing network customers to 

obtain credits going forward for existing facilities that are comparable to those the 

transmission provider includes in its revenue requirement would be a reasonable remedy 

for past discrimination. Noting the Commission’s requirement for transmission providers 

to remove all generator step-up facility costs from their transmission rates (not only those 

costs incurred after the Commission changed its policy in Order No. 888), TAPS maintains 

that the “correct and fair approach” is to prospectively remedy such discrimination by 

 135 E.g., APPA, East Texas Cooperatives, FMPA, NRECA, TAPS and TDU 

Systems. 
Docket No. RM05-17-001, et al. - 185 -

applying the new standard to both existing and new facilities.136 To do otherwise would, in 

TAPS’ view, undermine comparability. 

359. TDU Systems argue that the Commission cannot endorse rates that it knows are 

unjust and unreasonable and, therefore, agree that transmission customers should be 

credited for transmission facilities regardless of their vintage to the extent the facilities 

have not been subject to a prior determination. TDU Systems contend that Order No. 890 

failed to adequately justify allowing rates to remain in place that reflect undue 

discrimination. FMPA argue that comparability similarly requires that the Commission 

apply the presumption of integration to existing as well as new customer-owned facilities, 

since both existing and new transmission provider-owned facilities are presumed to provide 

benefits to the grid. 

360. Entergy and Florida Power ask that, to the extent the Commission applies the new 

test to transmission provider facilities, the rule apply only to new facilities constructed by 

the transmission provider, not to existing facilities. 

 Commission Determination 

361. The Commission denies rehearing of the decision to apply the modified test for 

credits only to transmission facilities added subsequent to the effective date of Order No. 

890. In light of the new planning and coordination required in Order No. 890, it is 

 136 TAPS also cites Tennessee Gas Pipeline Co., 104 FERC ¶ 61,063 (2003), order 

on reh’g, 108 FERC ¶ 61,177 (2004), order on reh’g, 110 FERC ¶ 61,385 (2005) for the 

proposition that new policies can be implemented for existing contracts. 
Docket No. RM05-17-001, et al. - 186 -

appropriate to apply the new test on a prospective basis.137 Existing facilities, by 

definition, have been developed without the benefit of the planning-related reforms 

adopted in Order No. 890 and, therefore, are not similarly situated to new facilities 

developed after the effectiveness of Order No. 890. As a result, only a network customer’s 

new facilities will be subject to the presumption of integration standard. Similarly, the 

existing presumption applied to the transmission provider’s facilities will continue to allow 

it to include in its rate base from the outset all network facilities constructed to meet its 

obligations to its customers, provided the presumption is not rebutted. 

d. Cost of Customer Facilities Automatically Included in 

Transmission Provider Cost of Service Without a Rate 

Filing

362. Noting that automatic recovery of the costs of credits would be contrary to the 

Commission’s long-standing policy concerning single-issue rate adjustments, the 

Commission declined to generically allow automatic recovery of the costs of credits 

associated with integrated transmission facilities to the transmission provider’s cost of 

service. The Commission explained that transmission providers continue to have the 

option to propose an automatic adjustment clause in their rates under FPA section 205 to 

address the time lag between incurring costs associated with credits and the transmission 

provider’s next rate case. 

 137 Order No. 890 at P 758. 
Docket No. RM05-17-001, et al. - 187 -

 Requests for Rehearing and Clarification 

363. Florida Power requests that the Commission grant rehearing of the decision that 

customer credits do not warrant an exception to the Commission’s general policy 

regarding single-issue rate adjustments. Florida Power argues that a transmission 

provider should not be required to dedicate the extensive resources required by a fullblown rate case to recover costs that, in its view, it has been forced to incur by the 

Commission’s policy and over which it has no control. 

364. E.ON U.S. requests that the Commission clarify that payment of credits is 

dependent on the transmission provider’s ability to recover the costs of the credits. E.ON 

U.S. asks that the Commission adopt one of the following requirements: if the network 

customer’s facilities are to be eligible for credits, the network customer must petition the 

Commission for a declaratory order stating that the transmission provider will be able to 

recover costs for the credits in the transmission provider’s next rate case; the transmission 

provider need not provide the network customer with credits for its facilities until the 

costs of the credits are approved in the transmission provider’s next rate case; or if the 

cost of the credits are rejected in the transmission provider’s next rate case, the network 

customer is required to refund any amounts collected through the transmission credits, 

plus interest. 

365. APPA asks that the Commission clarify that, if a transmission provider denies 

credits for network customer owned facilities, the transmission provider has a 

corresponding obligation to take steps to strip the costs of similar transmission facilities 

out of its own transmission revenue requirement where comparability requires such a 
Docket No. RM05-17-001, et al. - 188 -

result. TAPS argues that nothing in Order No. 890 altered the transmission provider’s 

existing obligation to remove from its rate base transmission provider facilities 

comparable to those for which it denies credits to network customers. 

 Commission Determination 

366. The Commission affirms its decision in Order No. 890 not to generically allow 

automatic rate recovery of the costs of credits associated with integrated transmission 

facilities to the transmission provider’s cost of service. As explained in Order No. 890, 

automatic recovery would be contrary to our long-standing policy concerning single-issue 

rate adjustments, and transmission providers continue to have the option to propose an 

automatic adjustment clause in their rates under FPA section 205 to address the time lag 

between incurring costs associated with credits and the transmission provider’s next rate 

case.138 Since transmission providers may choose to add an automatic adjustment clause 

to their rates to address any lag in cost recovery, we reject as unnecessary the alternative 

proposals offered by E.ON U.S. 

367. As for APPA’s argument regarding the transmission provider’s obligation to 

remove nonintegrated facilities from its revenue requirement, as explained above, the 

denial of credits for a network customer will no longer trigger an examination of the 

transmission provider’s own facilities. Rather, the presumption of integration shall be 

rebuttable for transmission providers and customers alike. If it becomes apparent that the 

transmission provider has included facilities in its revenue requirement that are ineligible, 

 138 See id. at P 766. 
Docket No. RM05-17-001, et al. - 189 -

such as when the transmission provider relies on its own facilities to demonstrate the lack 

of integration for customer-owned facilities, the network customer or the Commission, as 

appropriate, may initiate a complaint proceeding to have such facilities removed from 

rates. 

e. RTO and ISO Issues

368. The Commission concluded in Order No. 890 that it would not be appropriate to 

generically exempt all RTOs and ISOs from the revised requirements regarding credits 

for network transmission customers. The Commission stated that it would address issues 

relating to network transmission customer credits in the RTO and ISO context in orders 

addressing OATT reform compliance filings submitted by each RTO and ISO. The 

Commission noted its prior determination that the existing tariffs of certain RTOs and 

ISOs provide opportunities for transmission customers to receive credit or the equivalent 

(e.g., Transmission Congestion Contracts, Firm Transmission Rights or Auction Revenue 

Rights) for building facilities or upgrades that are consistent with or superior to Order 

No. 888 requirements.139 The Commission explained that each RTO and ISO would have 

the opportunity to show on compliance that this continues to be the case given the 

reforms adopted in Order No. 890. 

369. The Commission also addressed a request by NRECA to prohibit RTOs and ISOs 

from using a non-public utility’s transmission facilities without compensating the entity 

because it is not a member of the RTO/ISO. The Commission found that there is not 

 139 See id. at P 773, n.447. 
Docket No. RM05-17-001, et al. - 190 -

enough evidence on the record to make a generic determination on that issue. The 

Commission instead concluded it would be appropriate to address such issues on a caseby-case basis in response to appropriate filings under FPA sections 205 and 206. 

 Requests for Rehearing and/or Clarification 

370. TAPS is concerned that Order No. 890 suggests that RTOs/ISOs can justify an 

exemption from OATT section 30.9 by claiming that firm transmission rights or similar 

mechanisms are the “equivalent” of credits under section 30.9. TAPS states that the 

RTO/ISO tariff provisions referred to by the Commission relate only to upgrades, which 

are funded by a customer but owned by a transmission owner, for a new service request 

or generator interconnection. TAPS therefore requests clarification that the rules with 

respect to whether a network customer funding facilities owned by a transmission owner 

should receive firm transmission rights in lieu of credits are unrelated to, and should not 

be confused with, the requirement in OATT section 30.9 that a network customer must be 

compensated for customer-owned facilities in a manner comparable to transmission 

owners. 

371. NRECA reiterates its argument that the Commission should require RTOs/ISOs to 

compensate non-jurisdictional entities for use of the non-jurisdictional entities’ 

transmission facilities as required by the principle of comparability. NRECA argues that 

the issue is purely legal and that no additional evidence is necessary, since NRECA is not 

seeking a ruling that a particular entity is entitled to compensation. NRECA states that 

the Commission’s reliance on a “case-by-case” approach will be illusory if the 

Commission dismisses a complaint by a non-jurisdictional utility on the ground that the 
Docket No. RM05-17-001, et al. - 191 -

Commission has no jurisdiction over the non-jurisdictional entity’s rates under sections 

205 and 206 of the FPA, as it did in Central Iowa Power Coop.

140

 Commission Determination 

372. It was not the Commission’s intention in Order No. 890 to prejudge whether 

Transmission Congestion Contracts, Firm Transmission Rights or Auction Revenue 

Rights should be treated as equivalents to the credits available under section 30.9 of the 

pro forma OATT. The Commission simply noted that those mechanisms exist and that 

the Commission would determine, as it evaluated compliance filings from individual 

ISOs and RTOs, whether such mechanisms served the same purpose and goal of section 

30.9 and, in turn, should be considered proper substitutes for network customer credits. 

To the extent TAPS or others object to proposals made by a particular RTO or ISO, the 

appropriate forum to address those concerns is in the relevant compliance docket. 

373. In response to NRECA, we continue to believe that it is appropriate to consider on 

a case-by-case basis customer claims that RTOs or ISOs are using the transmission 

facilities of a non-public utility without compensation. It would not be appropriate to 

address this issue in a vacuum, without a complete discussion by interested parties of the 

legal and policy merits of both sides of this issue. 

 140 Central Iowa Power Coop. v. Midwest ISO, 110 FERC ¶ 61,093, order on 

reh’g, 113 FERC ¶ 61,116 (2005). 
Docket No. RM05-17-001, et al. - 192 -

3. Capacity Reassignment

a. Removal of the Price Cap

374. The Commission concluded in Order No. 890 that it is appropriate to lift the price 

cap for all transmission customers reassigning point-to-point transmission capacity, i.e., 

resellers. The Commission found that the price cap had served to reduce transmission 

options for customers and impair the development of a secondary market for transmission 

capacity. The Commission concluded that removing the price cap will allow capacity to be 

allocated to those entities that value it the most, thereby sending more accurate price 

signals for identification of the appropriate location for construction of new transmission 

facilities to reduce congestion. 

375. To enhance oversight and monitoring by the Commission of the secondary market 

for transmission capacity, certain reforms were adopted to the underlying rules governing 

capacity reassignments. First, the Commission required that all sales or assignments of 

capacity be conducted through, or otherwise posted on, the transmission provider’s OASIS 

on or before the date the reassigned service commences. Second, the Commission required 

that assignees of transmission capacity execute a service agreement with the transmission 

provider prior to the date on which the reassigned service commences. Third, in addition 

to existing OASIS posting requirements, the Commission required transmission providers 

to aggregate and summarize in an electric quarterly report (EQR) the data contained in the 

service agreements for reassigned capacity. The Commission explained that, taken 

together, these reforms will increase the transparency of capacity reassignments and 

facilitate our monitoring of the secondary market for transmission capacity. 
Docket No. RM05-17-001, et al. - 193 -

Requests for Rehearing and Clarification

376. Several petitioners request rehearing of the decision to lift the price cap on 

reassigned capacity.141 Some petitioners question the Commission’s stated justifications for 

the removal of the price cap. TDU Systems contend that the non-cost factors cited by the 

Commission, including promotion of the secondary market, enabling customers to better 

manage the risk of their long term commitments required by the reform of rollover rights, 

and sending more accurate price signals for capacity, do not justify lifting the price cap or 

substitute for analyzing the potential for the exercise of market power before lifting it. 

TDU Systems, APPA, and NRECA challenge the Commission’s conclusion that removing 

the price cap for capacity reassignments will stimulate greater infrastructure investment by 

sending more accurate price signals as to the incremental cost of transmission capacity. 

They argue that explicit congestion price signals in RTO markets have failed to stimulate 

investment and, in any event, are useless for transmission customers that lack the 

regulatory certainty required to facilitate third-party construction of new facilities. APPA 

argues that entrenched economic interests often find it more profitable to pocket the 

remaining dollars than to invest in new facilities. 

377. These petitioners all disagree with the Commission’s finding that the price cap has 

impaired the development of a secondary market for transmission. They argue that the 

Commission cites no support for this finding and that it failed to address comments in 

response to the NOPR stating that non-price limitations on capacity reassignment, such as 

 141 See, e.g., APPA, NRECA, and TDU Systems. 
Docket No. RM05-17-001, et al. - 194 -

the requirement that the assignee use the same source and sink as original customers, are 

the real reason that reassignments of capacity do not occur. APPA also contends that the 

Commission failed to explain why the lifting of the price cap is necessary to spur 

investment in light of other reforms adopted in Order No. 890, such as a more robust 

transmission planning process and the provision of planning redispatch and conditional 

firm point-to-point service. 

378. TAPS argues that the precedent relied upon by the Commission in Order No. 890 

does not support the decision to lift the price cap for reassigned capacity. TAPS states that, 

in Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines and 

Regulation of Negotiated Transportation Services of Natural Gas Pipelines,

142 the 

Commission actually required a market power analysis to justify market-based rates. 

TAPS argues that in Interstate Nat’l Gas Ass’n of America v. FERC,

143 the D.C. Circuit 

relied on empirical evidence to affirm the Commission’s decision to lift the cap on gas 

pipeline capacity releases. In that case, TAPS argues that: there was a significant amount 

of firm capacity going unused, suggesting that excess capacity could constrain prices and 

with evidence that it did in fact put a downward pressure on prices; evidence existed that 

new entry could restrain prices; and, the price cap at issue was lifted only for two years 

during an experiment. TAPS argues that similar empirical evidence is required, showing 

 142 74 FERC ¶ 61,076, reh’g denied, 75 FERC ¶ 61,024 (1996), petitions for 

review denied sub. nom. Burlington Resources Oil & Gas Co. v. FERC, 172 F.3d 918 

(D.C. Cir. 1998). 

143 285 F.3d 18 (D.C. Cir. 2002) (INGAA). 
Docket No. RM05-17-001, et al. - 195 -

that prices for secondary transmission capacity above the cap would be competitive and 

that new entry could constrain prices. 

379. Petitioners generally argue that removal of the price cap may expose transmission 

customers to market power and is therefore contrary to Commission and judicial precedent. 

APPA and TAPS argue that the Supreme Court has rejected seller claims justifying higher 

prices for electricity based upon the value ascribed to the product by the buyer, stating that 

a “focus on the willingness to pay or ability of the purchaser to pay for a service is the 

concern of a monopolist, not a government agency charged both with assuring the industry 

a fair return and with assuring the public reliable and efficient service, at a reasonable 

price.”144 In their view, this precedent requires the Commission to maintain the price cap 

in the absence of hard evidence of a competitive market for reassigned capacity. 

380. Joined by NRECA and TDU Systems, APPA and TAPS argue that the Commission 

is allowed to authorize market-based rates only with empirical proof that existing 

competition would ensure that the actual price is just and reasonable and that 

undocumented reliance on market forces will not suffice.145 In their view, the Commission 

must engage in an ex ante competitive analysis to find that the seller lacks market power, 

or take sufficient steps to mitigate market power, as well as adopt sufficient post-approval 

 

144 Quoting Gainsville Utilities Department, et al. v. Florida Power Corp., 402 U.S. 

515, 528 (1971). 

145 Citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d 1486 (D.C. Cir. 

1984) (Farmers Union) (finding that the Commission failed to justify relaxation of costbased regulation of oil pipeline companies because it did not ensure rates would remain 

within the zone of reasonableness). 
Docket No. RM05-17-001, et al. - 196 -

reporting requirements.146 These petitioners argue that the Commission’s reliance on 

competition among resellers, continued rate regulation of primary capacity, and the 

reassignment-related reforms adopted in Order No. 890 is insufficient to justify lifting the 

cap. 

381. With regard to competition among resellers, APPA contends that transmission 

capacity is a scarce commodity and demand is currently inelastic, due in part to substantial 

load growth. APPA argues that allowing point-to-point customers to make virtually 

unlimited profits from reassignments of their firm service will not further competition 

among resellers and, instead, may discourage participation in joint planning to support 

expansion or acceptance of increased rates to support new facilities. APPA acknowledges 

that firm transmission not scheduled will be released on a non-firm basis, but argues that is 

of little use to LSEs in need of firm transmission to deliver their firm power supplies. 

382. NRECA and TDU Systems argue that it is contradictory for the Commission to 

conclude that competition among resellers will assure just and reasonable prices when, 

elsewhere in Order No. 890, the Commission acknowledges congestion and the number of 

curtailments has dramatically increased in recent years. These petitioners question what 

market forces would constrain prices for secondary capacity at or below the price of 

primary capacity if primary capacity is so scarce. They question how it can be just and 

reasonable to price secondary rights at a level higher than the just and reasonable price of 

primary capacity. TAPS argues that a market power study of particular transmission paths 

 146 Citing California ex. rel. Lockyer, 383 F.3d 1006 (9th Cir. 2004) (Lockyer). 
Docket No. RM05-17-001, et al. - 197 -

is necessary to support a finding that competition among resellers will restrict market 

power. 

383. With regard to the availability of primary capacity at cost-based rates, TAPS argues 

that the Commission has presented no factual basis to conclude that entry will be timely, 

likely or sufficient to defeat price increases due to transmission market power. TAPS 

contends that, where capacity is fully subscribed, non-existent capacity cannot act as a 

price restraint. APPA argues that any requirement for the transmission provider to build 

new facilities in future years has little if any bearing on the price an LSE is willing to pay 

for the next day, week or month to ensure it meets its service obligation. NRECA and 

TDU Systems contend that, notwithstanding the planning-related reforms of Order No. 

890, transmission providers can continue to exert market power by refusing to expand the 

system to meet competitors’ needs. TDU Systems contends that failure to mandate 

expansion of the grid or to encourage third party construction of needed upgrades will 

ensure a lack of expansion, allowing the holder of rights to transmission capacity to exert 

monopoly power in a secondary market unprotected by price caps. 

384. Petitioners maintain that the revised oversight and reporting requirements adopted in 

Order No. 890 are insufficient to protect transmission customers from the exercise of 

market power. APPA and NRECA argue that post hoc reporting cannot prevent real-time 

harm to transmission customers and the end-users they serve or relieve the Commission of 

the obligation to ensure, at the outset, that the secondary market for capacity is competitive. 

TDU Systems similarly contend that the new posting and reporting requirements are 

unlikely to restrain the exercise of market power, since monthly reports will lag 
Docket No. RM05-17-001, et al. - 198 -

significantly behind the daily and hourly market transactions, even though greater price 

transparency may make market power easier to detect after the fact. 

385. MISO argues that, instead of relying on continued regulation in the primary market 

and competition in the secondary market to limit the exercise of market power in the 

secondary market, the Commission should provide for a sharing mechanism between the 

reseller and the owner of the transmission asset to allocate any market premium obtained 

from the resale. MISO contends that revenue sharing would reduce incentives to engage in 

hoarding on the part of the reseller and encourage efficient use of the grid. In its view, 

sharing market premiums would have a solid ground in equity, ensuring that the owners of 

transmission, constrained by cost-based rates, are not unduly discriminated against in favor 

of the reseller. 

386. APPA also contends that the use of value-of-service pricing for firm transmission 

service that LSEs require to meet their loads’ needs violates FPA section 217(b)(4) 

because it does not enable the LSEs to secure the firm transmission rights they need to 

serve their loads as Congress intended. While not specifically opposing the Commission’s 

decision to lift the price cap on reassignments of transmission capacity, South Carolina 

E&G makes a similar request that removal of the price cap be subject to the Commission’s 

assurances that the resulting increased use of the grid will not compromise service to native 

load customers. In its view, an active secondary market could crowd the limits of the grid 

and increase the likelihood of curtailments. Southern Carolina E&G argues that FPA 

section 217 requires that native load service not be marginalized a result of any increased 

use of the grid. 
Docket No. RM05-17-001, et al. - 199 -

387. If the Commission declines to reinstate the price cap on assignments of transmission 

capacity, TAPS asks that the Commission take two steps to offer consumer protection. 

First, TAPS asks the Commission to require utilities seeking to reassign transmission 

capacity to demonstrate a lack of transmission market power. TAPS argues that this 

demonstration should examine each point of receipt/point of delivery pair as a distinct 

market, unless the public utility can show that alternative paths provide meaningful 

substitutes. Second, TAPS asks the Commission to lift the price cap only for short-term 

services and only for a period of two years. TAPS suggests that, at the end of this period, 

the Commission should assess whether prices for reassigned capacity are competitive and 

whether the experiment produced the desired increase in reassigned capacity. 

Commission Determination 

388. The Commission affirms the decision in Order No. 890 to remove the price cap on 

reassignments of transmission capacity. We continue to believe that removal of the price 

cap will give market participants additional options for acquiring transmission. Point-topoint transmission service customers will have increased incentives to resell their service 

whenever others place a higher value on it. Existing transmission therefore will be put to 

better, more efficient use. Point-to-point customers also may be willing to commit to buy 

additional transmission service (such as for periods long enough to get rollover rights) 

since they are able to resell above the price cap during periods in which they do not need 

the capacity. On this basis alone, we find that establishing a competitive market for 

secondary transmission capacity will send more accurate signals that promote efficient use 

of the transmission system by fostering the reassignment of unused capacity. 
Docket No. RM05-17-001, et al. - 200 -

389. We agree with petitioners that restricting reassignment to the same point of receipt 

and point of delivery has limited, and may continue to limit, the number of reassignments 

that take place. It does not follow, however, that the price cap is irrelevant or that lifting 

the cap will not encourage additional reassignments of transmission capacity. Petitioners 

acknowledge that the secondary market for transmission capacity is underdeveloped. Even 

if the price cap is not the sole cause for this lack of development, it is at least a contributing 

factor. While other reforms adopted in Order No. 890 also will facilitate use of and 

investment in the transmission system, this does not mean that lifting the price cap on 

capacity reassignments is unnecessary or unimportant. The reforms adopted in Order No. 

890, including the decision to lift the price cap, work together to enhance customer options 

and the transmission provider’s operation of the grid. 

390. We are sensitive, however, to the concerns expressed by petitioners and grant 

rehearing to limit the period during which reassignments may occur above the cap. In 

Order No. 890, the Commission directed staff to closely monitor the quarterly 

reassignment-related data submitted by transmission providers to identify any problems in 

the development of the secondary market and to prepare a report on staff’s findings for the 

Commission within 6 months of the receipt of two years worth of data, i.e., by May 1, 

2010. Upon further consideration, we conclude that it is most appropriate to lift the price 

cap on reassignments of capacity only to accommodate this study period and amend 

section 23.1 of the pro forma OATT to reinstate the price cap as of October 1, 2010. Upon 

review of the staff report and any feedback from the industry, the Commission can 
Docket No. RM05-17-001, et al. - 201 -

determine whether it is appropriate to continue to allow reassignments of capacity above 

the price cap beyond that date. 

391. We disagree that a market power study or other empirical competition analyses are 

required to lift the price cap on capacity reassignments during this study period. Contrary 

to petitioners’ assertions, market power analyses are not the only method to ensure that 

market-based rates remain just and reasonable.147 In INGAA,

148 the court affirmed the 

Commission’s removal of price ceilings for short-term capacity releasing shippers in the 

natural gas market without requiring sellers to submit market power analyses, recognizing 

non-cost factors such as the need to lift price ceilings to facilitate movement of capacity 

into the hands of those who value it most. The court concluded that these non-cost factors, 

combined with the limitation of negotiated rates to the secondary market, distinguished the 

case from Farmers Union.

149 Similarly, continuing rate regulation of the transmission 

provider’s primary capacity, competition among resellers, and reforms to the secondary 

market for transmission capacity, combined with enforcement proceedings, audits, and 

 147 See Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas 

Pipelines and Regulation of Negotiated Transportation Services of Natural Gas Pipelines, 

74 FERC ¶ 61,076 at 61,227-36 (1996). The Commission ultimately determined in that 

case that a market power analysis was required in order to allow a pipeline to use marketbased pricing instead of cost-of-service rates. The Commission has not proposed to allow 

transmission providers to engage in sales of primary capacity at market based rates and, 

as explained below, sufficient protections exist to ensure the secondary market for 

transmission capacity remains sufficiently competitive without requiring market power 

analyses from each reseller. 

148 285 F.3d at 33. 

149 INGAA, 285 F.3d at 31-34. 
Docket No. RM05-17-001, et al. - 202 -

other regulatory controls, will assure that prices in the secondary market for transmission 

capacity remain within a zone of reasonableness.150

392. Petitioners inappropriately discount the importance of these regulatory protections, 

particularly the continued rate regulation of primary transmission capacity. Unlike gas 

pipelines, transmission providers are obligated to construct new facilities to satisfy a 

request for service if that request cannot be satisfied using existing capacity. The pro 

forma OATT does not, and will not, permit the withholding of transmission capacity by the 

transmission provider and effectively establishes a price ceiling for long-term 

reassignments at the transmission provider’s cost of expanding its system. Petitioner 

arguments to the contrary assume non-compliance with the transmission provider’s 

obligations under the pro forma OATT. If a customer has evidence of such noncompliance, it should bring the matter to the Commission’s attention through a complaint 

or other appropriate procedural mechanism. Absent such evidence, the Commission 

concludes that the continued rate regulation of the primary market, and the transmission 

provider’s obligation to expand its system to accommodate service requests, adequately 

mitigates any market power that resellers may have in the long-term secondary market. 

393. Pending the completion of upgrades, we acknowledge that delays associated with 

constructing new facilities could limit the downward effect that the transmission provider’s 

cost of expansion has on prices. Resellers could attempt to gain market power through 

economic or physical withholding of their primary capacity when congestion arises. As the 

 150 See Order No. 890 at P 811. 
Docket No. RM05-17-001, et al. - 203 -

Commission found in Order No. 890, however, competition among resellers, as well as the 

ability of customers desiring additional capacity to access primary capacity using 

conditional firm point-to-point service or the modified planning redispatch implemented in 

Order No. 890, will mitigate the exercise of market power in the interim.151 Moreover, any 

primary capacity that is not scheduled is made available to other customers on a non-firm 

basis, frustrating any attempts to withhold capacity.152

394. Reforms to the rules governing reassignments and associated reporting obligations 

also increase our regulatory oversight of the secondary market, allowing the Commission 

to effectively monitor that market for any attempts to exercise market power. All 

reassignments must now be conducted through or otherwise posted on OASIS and 

assignees must execute service agreements prior to the date on which service commences. 

Transmission providers must provide information regarding reassignments in their 

EQRs.153 As noted above, Commission staff will also closely monitor the quarterly 

reassignment-related data submitted by transmission providers and prepare a report on 

 151 See Order No. 890 at P 809, 812. 

152 See id. at P 811. 

153 As TDU Systems point out, the reports will lag behind the daily and hourly 

transactions in the market. As explained above, competition among resellers and 

regulatory protections embedded in the pro forma OATT will ensure that prices remain 

within the zone of reasonableness in the immediate near-term. The reports will enable 

the Commission to identify trends in the market and inefficiencies that may occur. 

Furthermore, if parties see that particular holders of transmission capacity are attempting 

to exercise market power through hoarding or other tactics, they can report such instances 

to the Office of Enforcement for investigation without delay. 
Docket No. RM05-17-001, et al. - 204 -

staff’s findings for the Commission’s consideration. The Commission takes seriously the 

possibility that resellers may attempt to exercise market power in the secondary market for 

transmission capacity. We continue to believe, however, that the regulatory protections in 

place and our increased oversight of this market will limit the potential for market power 

abuse during the period in which the price cap is lifted. There is no need for particularized 

market power studies regarding secondary transmission capacity, as suggested by TAPS. 

395. We disagree with NRECA and TDU Systems that the potential for secondary prices 

to rise above primary capacity prices indicates that rates may not be just and reasonable. 

As the courts have recognized, prices in a competitive market should rise during periods 

when capacity is truly scarce in order to ensure that capacity is being allocated 

appropriately.154 The precedent cited by petitioners clearly permits the Commission to 

implement alternative pricing structures provided that safeguards are in place to ensure that 

rates remain within a zone of reasonableness.155 We continue to believe that the regulatory 

framework governing the reassignment of transmission capacity, combined with our 

increased oversight and enforcement authority, will ensure that the rates for secondary 

transmission capacity remain within the zone of reasonableness. At the same time, lifting 

 154 See INGAA, 285 F.3d at 18, 32 (“[B]rief spikes in moments of extreme 

exigency are completely consistent with competition, reflecting scarcity rather than 

monopoly... A surge in the price of candles during a power outage is no evidence of 

monopoly in the candle market.”). 

155 See Farmers Union, 734 F.2d at 1509-10; INGAA, 285 F.3d at 32-34; Lockyer, 

383 F.3d at 10-13; see also Environmental Action v. FERC, 996 F.2d 401, 410 (D.C. Cir. 

1993). 
Docket No. RM05-17-001, et al. - 205 -

the price cap will give primary transmission customers greater incentives to commit to 

long-term service because they will be able to resell above the cap during periods when 

they do not need the capacity. 

396. We decline to adopt a mechanism to share revenues from capacity reassignments 

with the transmission provider. Allocation of the entire reassignment premium to the 

reseller is appropriate because it promotes an efficient allocation of transmission capacity, 

while sharing of the premium could make a potential seller less likely to resell even though 

another customer places a higher value on the transmission service. The Commission 

addressed a similar request in Order No. 636-A and concluded that releasing shippers in the 

gas market should be entitled to receive the proceeds from reselling their capacity.156 

Notwithstanding differences in the secondary market for transmission capacity, we believe 

that a similar approach should be followed for transmission providers, particularly since 

they already receive their full cost-of-service through payments for the underlying primary 

capacity. In any event, it would only be fair to share premiums with the transmission 

provider if losses were also shared when capacity was resold for less than the cost to the 

reseller of the capacity. Such sharing could lead to under-recovery of costs contrary to the 

premise of cost-of-service rates. 

 156 See Pipeline Service Obligations and Revisions to Regulations Governing SelfImplementing Transportation; and Regulation of Natural gas Pipelines After Partial 

Wellhead Decontrol, Order No. 636-A, 57 FR 36128 (August 12, 1992) FERC Stats. & 

Regs., Regulations Preambles January 1991 – June 1996 ¶ 30,950 at 30,562 (1992) 

(“Since the pipeline is not releasing the capacity, no efficiency or other pro-competitive 

goal would be furthered by allowing it to retain incremental proceeds.”). 
Docket No. RM05-17-001, et al. - 206 -

397. Finally, we do not believe that assignments will impose risks upon native load 

customers in contravention of FPA section 217 by increasing the likelihood of 

curtailments. Transmission providers should be planning the operation of their system to 

accommodate all reserved uses. Simply reassigning primary capacity from one customer 

to another should not alter the transmission provider’s ability to satisfy its service 

commitments. We also disagree that lifting the price cap on reassignments of capacity will 

make it more difficult for LSEs to obtain firm capacity to serve their load or otherwise 

marginalize native load service, as APPA suggests. Lifting the price cap should encourage 

primary capacity holders to make more, not less, transmission available to other customers, 

including LSEs. While it is true that secondary capacity may at times be more expensive 

than primary capacity, establishing a competitive market for secondary transmission 

capacity will benefit all customers, including LSEs, by sending more accurate signals that 

promote efficient allocation of transmission capacity. 

b. Lifting the Price Cap for Merchant Function and 

Affiliates 

398. The Commission declined in Order No. 890 to adopt the NOPR proposal to retain 

price caps for capacity resold by a transmission provider’s merchant function or its 

affiliates. After reviewing the comments submitted in response to the NOPR, and further 

considering its experience regulating capacity reassignments, the Commission concluded 

that retaining price caps for this portion of the market would continue to impair 

development of the secondary market and that price caps for such capacity are not 

otherwise necessary to ensure just and reasonable rates. The Commission found that there 
Docket No. RM05-17-001, et al. - 207 -

are no significant market power concerns to justify retaining the price caps for any 

transmission customer, noting that the Commission did not distinguish between affiliated 

and non-affiliated transmission customers when the Commission initially found in Order 

Nos. 888 and 888-A that excess capacity reserved could be reassigned. 

Requests for Rehearing and Clarification

399. The same petitioners challenging the Commission’s decision to lift the price cap for 

reassignments of capacity object specifically to lifting the price cap for reassignments by 

the transmission provider and its affiliates. APPA argues that this decision will result in 

more limited primary capacity, since it will be in the economic interest of the transmission 

provider’s corporate family for the merchant function and/or affiliates of the transmission 

provider to buy any primary capacity that is available. APPA contends that such 

transactions would technically satisfy the transmission provider’s obligation to make 

primary capacity available to customers, but effectively convert primary capacity into 

secondary capacity not subject to a price cap. APPA acknowledges that the Commission 

found in Order No. 890 that the Standards of Conduct will mitigate the ability of an 

affiliate to hoard capacity, but argues that the Commission failed to explain how such 

mitigation would occur. 

400. TAPS expresses similar concern that the transmission provider will have an 

incentive to sell primary capacity to its merchant function or affiliates to get around the rate 

ceiling on primary capacity. If the secondary market is clearing at rates above the 

transmission provider’s rate ceiling, TAPS argues that the parent corporation will have the 

incentive to put as much capacity in the hands of its merchant function or affiliates as 
Docket No. RM05-17-001, et al. - 208 -

possible, reducing the amount of price-restraining primary capacity and producing higher 

revenues for the parent corporation for sales of monopoly transmission service. In TAPS’ 

view, costs associated with hoarding will not encourage resale if withholding profitably 

raises prices in the secondary market. TAPS also argues that the Commission’s decision is 

inconsistent with its conclusion elsewhere in Order No. 890 that transmission providers 

have an incentive to over-designate CBM, which TAPS states is a form of hoarding. TAPS 

complains that, although the Commission stated in Order No. 890 that it will monitor for 

hoarding behavior by transmission providers and their affiliates, it proposed no remedy in 

the event they engage in this behavior. 

401. APPA, TAPS and TDU Systems argue that lifting the price cap for the transmission 

provider’s merchant function and affiliate sales also will discourage transmission providers 

from constructing transmission capacity in an attempt to raise prices in the secondary 

market. They contend that corporate families profiting more from transmission capacity 

resold by its merchant function or unregulated affiliates will have a disincentive to build 

new transmission that would lower those resale prices. APPA argues that much of Order 

No. 890 is devoted to attempting to ensure that transmission providers do not discriminate 

in order to favor their own generation, yet lifting the resale cap for the transmission 

provider’s merchant function and affiliates gives transmission providers incentives to favor 

their own and their affiliates’ sale of reassigned capacity at unregulated rates and to limit 

construction of new transmission facilities and upgrades to keep the rates for such 

reassignments high. NRECA and TDU Systems agree, arguing that shareholders and 

senior management will be indifferent as to whether the profits are from primary or 
Docket No. RM05-17-001, et al. - 209 -

secondary markets, or from transmission or generation, and will seek to drive profits to 

monopoly levels if possible. TDU Systems argue that the fact that both affiliated and nonaffiliated transmission customers were permitted in Order No. 888 to engage in 

reassignments of capacity is irrelevant because the ability to reassign capacity invoked few 

market power concerns so long as the price cap remained. 

402. APPA also requests clarification as to whether the transmission capacity that a 

transmission provider’s merchant function uses to serve the transmission provider’s own 

retail loads is eligible for reassignment. If so, APPA argues that it is unduly discriminatory 

to deny network customers the ability to reassign their capacity. APPA contends that 

network service was developed specifically to provide to other LSEs a transmission service 

comparable to the transmission service that public utilities provide themselves. 

Commission Determination

403. The Commission affirms the decision in Order No. 890 to lift the price cap for 

capacity resold by any point-to-point transmission customer, including the transmission 

provider’s merchant function and its affiliates. We continue to believe that retaining the 

price cap for this portion of the market would impair development of the secondary market 

and is not otherwise necessary to ensure just and reasonable rates. In light of the 

protections discussed above, we find there are not significant market power concerns that 

would justify retaining resale price caps for any transmission customer. 

404. While it is true that lifting the price cap for reassignments of capacity could provide 

an economic incentive for the transmission provider’s merchant function or its affiliates to 

acquire transmission capacity in an attempt to exercise market power, the same is true for 
Docket No. RM05-17-001, et al. - 210 -

any customer. Under the Standards of Conduct, affiliated and unaffiliated customers have 

equal access to transmission-related information and, through the OASIS, equal 

opportunity to acquire primary transmission capacity. Thus, any customer could engage in 

speculative purchasing in an attempt to gain market power. The Commission found in 

Order No. 890 that the entire secondary market is now sufficiently competitive, in light of 

the reforms adopted, market forces, and other considerations, to justify lifting the price cap 

for all transmission customers reselling capacity.157 As we explain above, there are 

sufficient structural and regulatory protections to ensure that no holder of capacity is able 

to exercise market power, regardless of whether the customer is affiliated with the 

transmission provider. The transmission provider must offer all firm (including long-term 

conditional firm) and non-firm capacity that is available and award that capacity in a nondiscriminatory manner, which will undermine any customer’s attempt to exercise market 

power. It therefore would not be appropriate to distinguish between classes of customers 

when lifting the price cap for reassignments. 

405. We disagree that our decision will lead to lower investment in new facilities by 

transmission providers. The pro forma OATT places an affirmative obligation on 

transmission providers to expand their system in order to accommodate requests for 

service. In addition, Order No. 890 requires transmission providers to establish an open 

 157 See Order No. 890 at P 809. There the Commission distinguished its decision 

from the determination in Order Nos. 888 and 888-A to implement the price cap on all 

reassignments based on a finding that the entire secondary market was not sufficiently 

competitive to justify market-based pricing. 
Docket No. RM05-17-001, et al. - 211 -

and transparent planning process to ensure that transmission plans are developed on a nondiscriminatory basis. Transmission providers are also required to file reports with the 

Commission if they are late processing requests for new service and pay penalties if they 

are consistently late with service request studies. We conclude that these protections are 

adequate to ensure that transmission providers do not forego upgrades in an attempt to 

increase the value of capacity that has been assigned to their affiliates. 

406. Because the Commission has found the secondary market for transmission capacity 

to be sufficiently competitive, it would not be appropriate to distinguish between classes of 

customers reselling their capacity. As we state above, however, the Commission takes 

seriously allegations of market abuse and we reiterate our intent to be vigilant in overseeing 

this market. If the Commission finds evidence of market abuse, we will exercise our 

enhanced authority by restricting the ability of an offending reseller (and possibly its 

affiliates) to participate in the secondary market for transmission capacity or imposing 

other remedies, including civil penalties, as appropriate. Should any customer believe that 

capacity is being preferentially allocated to a transmission provider’s affiliates, that 

particular holders of transmission capacity are attempting to exercise market power through 

hoarding or other tactics, or that the transmission provider is failing to meet its expansion 

obligations, the customer should bring the matter to the Commission’s attention through a 

complaint or other appropriate procedural mechanism. We direct staff to include in its 

report any evidence of abuse in the secondary market for transmission capacity. 

407. With regard to APPA’s request for clarification regarding the ability of the 

transmission provider’s merchant function to reassign transmission capacity used to serve 
Docket No. RM05-17-001, et al. - 212 -

the transmission provider’s retail load, we reiterate that only point-to-point transmission 

customers may reassign their transmission capacity.158 To the extent the transmission 

provider’s merchant function or a network customer has acquired point-to-point 

transmission, either may resell that capacity in the secondary market. 

c. Contracting and Posting Issues 

408. As noted above, the Commission required in Order No. 890 that all sales or 

assignments of capacity be conducted through or otherwise posted on the transmission 

provider’s OASIS on or before the date the reassignment commences. The Commission 

thus eliminated the ability of transmission customers to assign transmission rights to 

another party with subsequent notification to the transmission provider. The Commission 

also directed transmission providers, working through NAESB, to develop appropriate 

OASIS functionality to allow such postings. Transmission providers were not required to 

implement this new OASIS functionality or any related business practices until NAESB 

develops appropriate standards. 

409. The Commission also required that assignees of transmission capacity execute a 

service agreement prior to the date on which the reassigned service commences. 

Transmission customers with market-based rate tariffs were no longer permitted to execute 

and implement assignments of capacity without involving the transmission provider, 

subject to after-the-fact reporting and posting. The Commission explained that this 

effectively returns the specified capacity to the transmission provider for the purpose of 

 158 See Order No. 890 at P 825. 
Docket No. RM05-17-001, et al. - 213 -

reassignment to the assignee and eliminates the need for the assigning party to have a rate 

schedule governing reassigned capacity on file with the Commission. The transmission 

provider’s OATT will govern the reassigned service, with the assignee paying the 

transmission provider for service at the negotiated rate and the transmission provider 

billing or crediting the reseller with any difference between the negotiated rate and the 

reseller’s original rate. All the non-rate terms and conditions that otherwise would apply to 

the transmission provider’s sale of transmission capacity continue to apply in the case of a 

reassignment. 

410. In addition to already existing OASIS posting requirements, the Commission 

required transmission providers to aggregate and summarize in an EQR the data contained 

in the service agreements for reassigned capacity. The Commission directed that the 

quarterly report be submitted in the EQR so that it is readily accessible to the Commission 

and the public. The Commission also revised section 23 of the pro forma OATT to address 

reassignments of transmission capacity and added a pro forma service agreement for 

reassignments in a new Attachment A-1. 

Requests for Rehearing and Clarification

411. Several petitioners request rehearing and clarification of the requirement that there 

must be a service agreement in place between the transmission provider and the assignee 

prior to the assignment commencing. Bonneville argues that requiring transmission 

providers to execute service agreements with assignees is too onerous and that it is 

unnecessary for the Commission to monitor more closely the secondary market for 

transmission capacity. Bonneville further argues that it would be virtually impossible to 
Docket No. RM05-17-001, et al. - 214 -

execute a service agreement for daily or hourly reassignments, harming the market for 

reassignments of short-term transmission. Bonneville also suggests that requiring a written 

contract for assignments may cause OASIS transactions between a reseller and assignee to 

be non-binding and force the transmission provider to maintain two systems for 

transactions, one electronic and one for paper transactions. 

412. Bonneville also contends that if an assignee fails to return an executed service 

agreement under the Commission’s new rules, transmission service could not commence 

even though the reseller and assignee concluded an assignment on OASIS. Bonneville 

claims that, under the Commission’s OASIS standards, the transmission provider has no 

ability to invalidate, refuse, decline, retract or annul an assignment on OASIS and, 

therefore, no ability to recall the assigned capacity from the assignee and return it to the 

reseller. Bonneville states that OASIS would show the reservation in the name of the 

assignee and the assignee would be able to schedule transmission without a service 

agreement, effectively nullifying the requirement. 

413. Joined by EEI, Bonneville suggests that the Commission clarify that the 

requirement to execute a service agreement with the assignee is satisfied by a previously 

executed umbrella agreement between the transmission provider and the assignee and that 

the execution of a service agreement covering a particular assignment is not required. EEI 

contends that this would be consistent with the current requirement for customers taking 

short-term firm and non-firm service under the pro forma OATT. EEI requests 

clarification that, regardless of whether the assignee has executed a service agreement with 

the transmission provider, the same OASIS posting requirements would apply to 
Docket No. RM05-17-001, et al. - 215 -

reassignments as apply to any reservation of transmission service. EEI argues that an 

assignee should be required to inform the transmission provider through an OASIS posting 

of the terms and conditions of the assignment so that the transmission provider and other 

customers are informed of the existence of a reservation for transmission capacity. 

414. Constellation argues that there is no basis in the record for the Commission to adopt 

formal assignment procedures for short-term reassignments. Constellation asks that the 

Commission grant rehearing to allow short-term and temporary assignments of 

transmission capacity to occur without a formal reassignment of the transmission service 

agreement. Constellation suggests that the Commission consider other means of separating 

the filing requirements for capacity reassignment from those for market-based rates tariffs, 

such as by establishing standardized tariff terms in its regulations and authorizing entities, 

upon notice to the Commission, to adopt those regulations as their filed tariff for 

reassignments. 

415. Several petitioners object to the billing mechanism adopted for capacity 

reassignments. Bonneville argues that transmission providers should be allowed to 

continue billing the reseller for the assigned capacity. Bonneville contends that requiring 

transmission providers to bill at the negotiated rate will insert the transmission provider 

into the financial arrangements of the reseller and the assignee, obligating the transmission 

provider to monitor the parties’ business arrangements and adjust its own operations to 

compensate. Bonneville also contends that transmission providers are not set up to charge 

assignees rates that are different from the normal transmission rate. If a robust assignment 

market develops, Bonneville states that transmission providers could have to charge dozens 
Docket No. RM05-17-001, et al. - 216 -

of different rates varying from day to day or even hour to hour. Bonneville suggests that 

both the reseller and assignee would likely be purchasing other transmission in addition to 

the assigned capacity, requiring the transmission provider to charge at least two different 

rates to the same customer. Bonneville contends that significant changes will have to be 

made to all transmission providers’ billing systems at substantial cost to the industry to 

accommodate the Commission’s reform of the rules governing capacity reassignment. 

416. EEI and Southern suggest that transmission providers be required to charge the 

assignee at the same rate that the reseller originally agreed to pay and allow the reseller and 

assignee to arrange for any difference between the original price and the negotiated 

reassignment price. Southern argues that requiring the transmission provider to act as 

settlement agent unnecessarily complicates and duplicates the transmission provider’s 

burdens and responsibilities, noting the Commission declined to impose such an obligation 

when third party generators provide planning redispatch.159 EEI argues that the service 

agreement with the reseller terminates when the assignee executes a new service agreement 

and, as a result, the transmission provider has no contractual basis to collect revenues from 

the reseller if the reseller has resold its capacity at a price lower than the price it agreed to 

pay the transmission provider.160 Joined by Washington IOUs, EEI suggests that requiring 

the transmission provider to charge the assignee at a rate different from the price stated in 

its OATT would violate either the discount rule or the ceiling price. If the Commission 

 159 Citing Order No. 890 at P 1160. 

160 Citing id. at P 816, n.496. 
Docket No. RM05-17-001, et al. - 217 -

declines to change its billing rules on rehearing, EEI requests that Schedules 7 and 8 of the 

pro forma OATT be amended to provide that ceiling prices and discounting rules do not 

apply in the context of reassigned transmission capacity. 

417. EEI contends that the Commission’s concerns with respect to the reporting of the 

price of reassigned capacity can be addressed without requiring the transmission provider 

to become involved in the payment stream related to the reassignment. EEI argues that all 

jurisdictional resellers of transmission report those transactions in their EQRs. If the 

Commission wants all capacity reassignments on a system to be in a single report, EEI 

argues it can require the assignee to inform the transmission provider of the price and other 

terms of service and the transmission provider can include this information in its EQR. 

418. Washington IOUs distinguish between long-term and short-term reassignments, 

arguing that different rules should be adopted for each type of transaction. For long-term 

reassignments, Washington IOUs argue that transmission providers should only be 

required to take on a bilateral relationship with an assignee where all rates, terms and 

conditions of the assignment are the same as the original rates, terms and conditions of the 

purchase of primary capacity. Otherwise, they contend the transmission provider may be 

unable to recover the rate owed to it in the event of a dispute between the reseller and 

assignee. For short-term reassignments, they argue the transmission provider should 

continue to bill the reseller for the assigned capacity scheduling rights, with the assignee 

paying the reseller directly. Washington IOUs contend that NAESB distinguishes between 

long-term and short-term reassignment transactions, which they argue is appropriate to 
Docket No. RM05-17-001, et al. - 218 -

ensure transmission providers are not unduly burdened by being forced to act as a 

middleman between resellers and assignees. 

419. TranServ contends that the NAESB standards distinguish between resales of 

scheduling rights and transfers of all obligations, including financial responsibilities. 

TranServ states that, under the NAESB standards, a resale does not alter the financial 

obligation for the capacity reassigned, which remains with the reseller. TranServ argues 

that the billing mechanism adopted in Order No. 890 inappropriately shifts this financial 

obligation to the assignee, unduly burdening the transmission provider with the 

responsibility to manage settlement of the reassignment. 

420. EEI asks the Commission to refer to NAESB the issue of whether any modifications 

to the OASIS protocols are required to implement the modifications to transmission 

reassignments required in Order No. 890. EEI requests that NAESB be directed to report 

to the Commission on whether modifications are required to implement transmission 

reassignments being posted before-the-fact rather than after-the-fact and if so, NAESB’s 

estimated timeline for development of such modifications. 

421. Several petitioners complain about the cost to the transmission provider of 

providing the accounting and billing for capacity reassignments. EEI and Washington 

IOUs contend that the Commission’s billing rules require the transmission provider to 

subsidize the administrative costs of the reassignment by collecting and distributing 

payments on behalf of the reseller and assignee. Washington IOUs argue that the 

transmission provider’s limited resources would be better used in areas more central to the 

transmission provider’s core responsibilities. MidAmerican asks that the Commission 
Docket No. RM05-17-001, et al. - 219 -

expressly limit the ability of assignees to further assign capacity, arguing that the 

administrative tracking and posting of additional reassignments would be costly. To the 

extent the Commission requires transmission providers to continue to credit and charge 

revenues from reassignments of capacity, E.ON U.S. and TranServ ask the Commission to 

clarify that transmission providers should be compensated for the accounting services they 

provide to act as billing agents for reassignments of capacity. Unless a compensation 

mechanism is spelled out in the pro forma OATT, these petitioners argue that the financial 

obligations between the reseller and assignee should remain with those parties. 

Commission Determination

422. The Commission affirms the decision in Order No. 890 to require assignees to 

execute a service agreement with the transmission provider governing reassignments of 

transmission capacity prior to scheduling use of that capacity. We provide clarification of 

this requirement, however, in response to the concerns raised by petitioners. In Order No. 

890, the Commission required that all reassignments be accomplished by the assignee 

executing a service agreement with the transmission provider that will govern the provision 

of reassigned service.161 The Commission did not intend to impose contracting obligations 

that are more onerous than the acquisition of primary transmission capacity, which may be 

accomplished through execution of a service agreement followed by scheduling on OASIS. 

 161 See id. at P 816. The Commission adopted corresponding revisions to section 

23.1 of the pro forma OATT requiring the execution of a service agreement prior to the 

date on which the reassigned service commences that will govern the provision of 

reassigned service. 
Docket No. RM05-17-001, et al. - 220 -

We clarify that it is equally sufficient for an assignee to execute a service agreement 

governing its reassignments of capacity generally and to complete a particular assignment 

through the OASIS. However, as with reservations of primary transmission capacity, there 

remains a threshold requirement to execute a service agreement with the transmission 

provider in order to commit the assignee to abide by the terms and conditions of the 

transmission provider’s OATT governing the reassignment of transmission service. 

423. It would not be appropriate to relieve assignees of the obligation to execute a service 

agreement with the transmission provider since such agreements establish the necessary 

contractual relationship between the assignee and the transmission provider. As we explain 

above, sales of reassigned capacity now take place under the transmission provider’s 

OATT and, thus, there must be a contractual relationship between these parties. This does 

not mean, however, that all of the terms and conditions of a particular assignment must be 

stated in the service agreement. Like short-term firm and non-firm reservations of primary 

capacity, the transmission provider and assignee may rely on OASIS to provide 

information regarding the reseller, quantity, and price associated with a particular 

reassignment of service. This information would then become part of the binding 

agreement between the transmission provider and assignee governing the assignment,162

just as confirmation of short-term firm and non-firm transactions on OASIS constitute 

binding contractual commitments. Because execution of a service agreement with the 

 162 The EQR for reassignments of transmission capacity must contain all relevant 

transaction data, whether stated in the service agreement or related OASIS schedule. 
Docket No. RM05-17-001, et al. - 221 -

transmission provider governing reassignments of capacity is a threshold requirement for 

an assignee wishing to accomplish a particular reassignment on OASIS, Bonneville’s 

concern regarding the failure of an assignee to return its service agreement is misplaced. 

The assignee in that instance would have no right to schedule a reassignment on OASIS 

since it has not first executed the appropriate service agreement with the transmission 

provider. 

424. Some of the confusion regarding these contracting requirements may have been 

caused by the Commission’s reference in section 23.1 of the revised pro forma OATT to a 

service agreement “that will govern the provision of reassigned service,” which could be 

interpreted to refer to transaction-by-transaction service agreements for reassignments. 

Inclusion of the words “Long-Term Firm” in both the title of the form of service agreement 

and the attached specifications in the new Attachment A-1 to the pro forma OATT adopted 

in Order No. 890 may have added to the confusion by potentially implying that use of the 

service agreement is limited to long-term firm point-to-point transactions instead of also 

applying to short-term firm point-to-point and non-firm point-to-point reassignments, as 

intended by the Commission.163 We revise section 23.1 of the pro forma OATT and the 

title of Attachment A-1 to make clear that use of the form of service agreement for 

 163 See pro forma OATT Attachment A-1, Form of Service Agreement for the 

Resale, Reassignment or Transfer of Long-Term Firm Point-to-Point Transmission 

Service. 
Docket No. RM05-17-001, et al. - 222 -

reassigned capacity, and associated posting of schedules and transaction information on 

OASIS, should be similar to the use of such agreements for primary capacity.164 

425. The execution of a service agreement by the assignee does not itself terminate the 

reseller’s service agreement, as EEI argues. The reseller’s service agreement remains in 

place, granting the reseller scheduling rights for the reserved capacity and obligating the 

reseller to pay for that reservation. During the term of the assignment, the reseller will 

continue to be billed under its agreement with the transmission provider. The assignment 

of service simply transfers to the assignee some or all of the reseller’s scheduling rights for 

the period of the reassignment and, in return, obligates the assignee to pay the transmission 

provider the negotiated rate. In order to prevent over-recovery by the transmission 

provider, the transmission provider must therefore credit the reseller the reassignment rate, 

which leaves the reseller with the net difference between the resale rate and the reseller’s 

original rate.165 If the assignee defaults and fails to pay for the reassigned capacity, the 

 164 As with the form of service agreement for firm point-to-point transmission 

service, we retain the specifications attachment for the form of service agreement 

governing reassignments. We understand that long-term agreements for reservations of 

primary capacity rely on the specifications attachment, so we would expect similar 

practices to be used regarding long-term reassignments of transmission capacity. As with 

any transaction, however, actual uses of primary and secondary capacity should be 

scheduled on OASIS consistent with applicable business procedures. 

165 If the reseller and assignee agree to a full transfer of the reseller’s rights and 

obligations, the reseller would only make payments to the extent the transfer is executed 

at a lower rate than the rate agreed to between the reseller and transmission provider, to 

ensure that the transmission provider receives the full contract price agreed to by the 

reseller. If the full transfer is executed at a rate in excess of the reseller’s contract with 

the transmission provider, the transmission provider must credit the reseller with the 

additional revenue as a result of the transfer. 
Docket No. RM05-17-001, et al. - 223 -

transmission provider should reverse the credit to the reseller to reflect the lack of payment 

by the assignee.166 

426. We disagree that these billing requirements are unduly burdensome. While it is true 

that the transmission provider may be required to bill at different rates, that is already the 

case under the pro forma OATT. Transmission providers are permitted to offer discounts 

from the rates stated in their OATT, provided they offer such discounts to all eligible 

customers. Offering discounts thus creates different rates for different customers 

depending on when they negotiate service. The transmission provider therefore should 

already have mechanisms in place to bill customers based on rates other than those stated 

in its OATT. In any event, the need to bill assignees directly for reassignments is 

inextricably linked to the decision to require that all reassignment transactions take place 

pursuant to the rate on file in the transmission provider’s OATT, rather than bilateral 

agreements between customers.167 We therefore do not intend for the discount rule or the 

price ceilings otherwise stated in the transmission provider’s OATT to apply to 

reassignments of capacity. We have revised schedules 7 and 8 of the pro forma OATT 

accordingly. 

 166 The transmission provider may take action against the assignee as it would any 

other default under the pro forma OATT. We recognize that, in this instance, the 

transmission provider may have little incentive to pursue collection since it will recover 

its original contract rate from the reseller, but it could transfer to the reseller its legal 

rights to enforce the assignee’s payment obligations. 

167 It is therefore irrelevant that payments for third-party planning redispatch are 

settled bilaterally, since the underlying planning redispatch service is not provided under 

the transmission provider’s OATT. 
Docket No. RM05-17-001, et al. - 224 -

427. We clarify that, to the extent necessary, the costs incurred by the transmission 

provider to account and bill for reassignments of transmission capacity should be included 

in the transmission provider’s cost of service, just like accounting and billing costs for any 

other service under the transmission provider’s OATT. We decline MidAmerican’s 

request to prohibit further assignments of reassigned capacity. Order No. 888 allowed for 

multiple reassignments under the pro forma OATT and MidAmerican does not justify 

departing from this practice. Just as the original transmission customer may find that it has 

excess capacity it can reassign, so may an assignee. Denying the assignee’s right to further 

assign its scheduling rights would inhibit customers who value the capacity most from 

accessing it and thereby contradict the Commission goal of creating a competitive 

secondary market for transmission capacity. 

428. With regard to OASIS modifications necessary to allow for the reassignment of 

transmission capacity, the Commission in Order No. 890 already directed transmission 

providers working through NAESB to develop appropriate OASIS functionality to allow 

for reassignment-related postings.168 We understand that this work is on-going and expect 

any necessary modifications to NAESB’s business practices that are necessary to reflect 

our rulings in this order will be adopted prior to the submission of those standards for 

Commission review. In the interim, transmission providers should identify in their 

business practices any procedures necessary to accomplish the reassignment of capacity by 

their customers. 

 168 See Order No. 890 at P 815. 
Docket No. RM05-17-001, et al. - 225 -

d. Market-Based Rate Tariffs

429. Because purchasers of transmission capacity in the secondary market will execute a 

service agreement directly with the transmission provider, the Commission stated in Order 

No. 890 that there will no longer be a need for the assigning party to have on file with the 

Commission a rate schedule governing reassignment capacity. The Commission explained 

that the transmission provider’s OATT will govern the reassigned service. 

Request for Rehearing and Clarification

430. EPSA and Powerex question how sellers with market-based rates are to proceed 

regarding the removal of the price cap stated in their market-based rates tariffs. In order 

not to violate their market-based rate tariffs, these petitioners contend that sellers may be 

obligated to file revisions of their tariffs and receive an order approving those revisions 

prior to reselling transmission above the cap. Powerex also suggests that existing marketbased rate tariffs require a seller of transmission capacity to continue reporting in its 

quarterly reports the name of an assignee. Powerex and EPSA request that the 

Commission deem void, as of the effective date of Order No. 890, the provisions in each 

individual seller’s market-based rate tariffs that impose a cap on resale prices and reporting 

obligations. Petitioners suggest that these resellers be permitted to update their marketbased rate tariffs at such time as the tariff is amended or with their next triennial update. 
Docket No. RM05-17-001, et al. - 226 -

Commission Determination

431. In Order No. 890, the Commission explained that reassignments of transmission 

capacity will now be governed by the transmission provider’s OATT.169 Each assignee 

must execute a service agreement directly with the transmission provider, which we clarify 

above may be an umbrella service agreement governing multiple reassignment transactions 

scheduled on OASIS. As a result, the sale of reassigned capacity is made by the 

transmission provider pursuant to the terms and conditions of its OATT, not by the reseller 

under its market-based rate tariff. Although the reseller may negotiate the relevant price 

with the assignee, the reassignment itself is governed by the transmission provider’s 

OATT. The reseller’s market-based rate tariff is no longer relevant or controlling. The 

Commission therefore explained in Order No. 890 that the reseller does not need to have 

on file with the Commission a rate schedule governing reassigned capacity. 

432. In Order No. 697, the Commission affirmed this approach, explaining that it is no 

longer appropriate to include in the market-based rate tariff transmission-related 

services.170 The Commission stated that reassignments of capacity are, instead, provided 

for in the revised pro forma OATT and that capacity holders seeking to reassign 

transmission capacity should adhere to the provisions of Order No. 890. Because these 

reassignment-related provisions of the market-based rate tariff were no longer needed, the 

 169 See id. at P 816, n.496. 

170 See Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity and 

Ancillary Services By Public Utilities, Order No. 697, 72 Fed. Reg. 39,904 (July 20, 

2007), FERC Stats. & Regs. ¶ 31,252 (2007). 
Docket No. RM05-17-001, et al. - 227 -

Commission directed sellers to revise their market-based rate tariffs to remove the 

provisions at the time they otherwise revise their tariffs to conform them to the standard 

provisions adopted in Order No. 697.171 

433. To the extent confusion remains as to the relationship between the market-based 

tariff and the transmission provider’s OATT, we reiterate that, as of the effective date of 

the reforms adopted in Order No. 890, all reassignments of capacity must take place under 

the terms and conditions of the transmission provider’s OATT. To the extent a reseller has 

a market-based tariff on file, the provisions of that tariff, including a price cap or reporting 

obligations, will not apply to the reassignment since such transactions no longer take place 

pursuant to the authorization of that tariff. As the Commission directed in Order No. 697, 

sellers should amend their market-based rate tariff to remove provisions regarding the 

reassignment of capacity when they otherwise revise their tariffs to conform them to the 

standard provisions adopted in Order No. 697. 

4. “Operational” Penalties 

a. Unreserved Use Penalties 

(1) Unreserved Use of Transmission Service and 

Inappropriate Use of Network Service

434. In order to eliminate a potential source of discretion in the implementation of the 

pro forma OATT and to enhance the Commission’s enforcement of OATT obligations, 

the Commission clarified, in Order No. 890, the application of unreserved use penalties. 

 171 Id. at P 920. 
Docket No. RM05-17-001, et al. - 228 -

The Commission determined that a transmission customer would be subject to unreserved 

use penalties in any circumstance where the transmission customer uses a transmission 

service that it has not reserved. Specifically, a transmission customer will be subject to 

an unreserved use penalty in circumstances where a transmission customer has a 

transmission reservation, but uses transmission service in excess of its reserved capacity. 

A transmission customer also will be subject to an unreserved use penalty if the 

transmission customer uses transmission service without the appropriate transmission 

reservation. 

435. The Commission declined to exempt any class of customers from the potential 

assessment of unreserved use penalties, including LSEs serving native load in multiple 

control areas, and noted that the transmission provider itself is subject to the same 

penalties when it takes transmission service under its OATT. The Commission stated 

that a network customer or transmission provider that inappropriately uses network 

transmission service to support off-system sales may be required to disgorge unjust 

profits from such sales, as the Commission may determine on a case-by-case basis. The 

Commission stated that it would evaluate the appropriateness of civil penalties in addition 

to unreserved use penalties on a case-by-case basis. The Commission concluded that it is 

appropriate to subject both a network customer and transmission provider inappropriately 

using network transmission service to unreserved use penalties because such action 

potentially uses or acquires, without an appropriate reservation, transmission service that 

could be allocated to other customers. The Commission modified the language of section 

30.4 of the pro forma OATT to clarify that network customers are subject to unreserved 
Docket No. RM05-17-001, et al. - 229 -

use penalties when they schedule delivery of off-system non-designated purchases using 

transmission capacity reserved for designated network resources. 

436. The Commission clarified that a network customer may use the undesignated 

portion of a remote network resource to serve network load using secondary network 

service and may use the undesignated portion of the resource for other non-network 

service purposes, such as third-party sales, as long as the network customer acquires the 

appropriate point-to-point service. The Commission also noted that, because the 

transmission provider does not have to “take service” under its OATT for the 

transmission of power that is purchased on behalf of bundled retail customers, it is free to 

use the undesignated portion of a remote network resource to serve its bundled retail 

customers. The Commission affirmed that, if the transmission provider desires to use a 

remote network resource for non-native load purposes, such as third-party sales, it must 

acquire the appropriate point-to-point service. 

437. In order to ensure that the transmission provider has a basis for charging an 

unreserved use penalty, the Commission modified section 13.4 of the pro forma OATT to 

provide that a customer that takes unreserved point-to-point transmission service and 

does not have a service agreement with the transmission provider is deemed to have 

executed the transmission provider’s form of service agreement for point-to-point 

service. The Commission also clarified that a customer that uses more transmission 

service than it has reserved is also subject to charges for ancillary services based on the 

period of unreserved use. The Commission modified section 3 of the pro forma OATT to 

reflect that rule. 
Docket No. RM05-17-001, et al. - 230 -

Requests for Rehearing and Clarification

438. AWEA seeks clarification of the Commission’s statement that intermittent 

resources could avoid unreserved use penalties by reserving sufficient transmission 

capacity to deliver the resource’s full output. AWEA asks that the Commission confirm 

that it did not intend to require resources to always reserve point-to-point transmission 

service based on the maximum potential output in order to avoid unreserved use 

penalties. AWEA contends that such a practice would be cost prohibitive for a wind 

generator, which often operates at less than full output, and could require multiple 

transmission reservations, up to full nameplate capacity, on multiple transmission paths 

for generators that market their output at multiple trading points from day to day. AWEA 

contends that determining whether a positive imbalance event results in an unauthorized 

use of transmission depends on whether the transmission provider is contractually 

obligated to deliver a resource’s actual or full output, or only a fixed amount of power, 

and, to the extent the positive generation imbalance is physically delivered from point A 

to point B, whether such delivery is covered by a transmission service reservation. 

439. If the Commission does not grant the requested clarification, AWEA requests 

rehearing to the extent Order No. 890 authorizes transmission providers to impose 

unreserved use penalties for every instance of positive generator imbalance. AWEA 

argues such a requirement would be inconsistent with the Commission’s refusal to 

delineate the specific circumstances that constitute unreserved use of the transmission 

system. AWEA further argues that applying unreserved use penalties in every instance of 

positive generation imbalance would subject generators to duplicative charges for an 
Docket No. RM05-17-001, et al. - 231 -

imbalance and would render uneconomic substantial numbers of wind power 

transactions. AWEA argues such a policy would be unjust, unreasonable and unduly 

discriminatory against wind power generators that have no ability to control the actual 

output of their facilities. 

440. TDU Systems argue that it is unjust and unreasonable for the Commission to 

subject LSEs to penalties for inadvertent uses of network service when managing loads 

and resources across a neighboring control area. TDU Systems contend that serving 

native load in multiple control areas requires managing resources across those boundaries 

and the flexibility to respond to changes in service requirements on a timely basis in a 

cost-efficient manner comparable to the way in which transmission providers use 

network service to manage their retail native load service obligations. In their view, 

inadvertent takes of transmission service in excess of reservations occur for reasons 

beyond the control of the LSE and, therefore, assessing unreserved use penalties is 

inappropriate. TDU Systems also object to the Commission’s statement that it would not, 

as a general policy, exempt an LSE’s unreserved use from potential civil penalties. TDU 

Systems argue that the imposition of civil penalties on LSEs that inadvertently violate the 

prohibition on unauthorized use would be unjust and unreasonable on its face. TDU 

Systems suggest that payment for the increment of service actually used but not reserved 

makes the transmission provider whole without visiting further penalties on behavior that 

is by definition unintentional. 

441. TDU Systems argue that inadvertent takes of transmission service in excess of 

reservations by an LSE serving native load in multiple control areas should be treated as 
Docket No. RM05-17-001, et al. - 232 -

an energy imbalance in the control area in which the energy imbalance occurs, rather than 

an unauthorized use of point-to-point service. TDU Systems object to the Commission’s 

characterization of energy imbalance charges as compensation to the transmission 

provider for the additional expense it incurs to compensate for a transmission customer’s 

failure to schedule sufficient energy to serve its load, arguing that imbalance charges 

contain a penal, above-cost component that make the transmission provider more than 

whole. In their view, the more onerous unreserved use charges should be reserved for 

intentional over-scheduling of transmission reservations. 

442. In order to prevent inadvertent uses from occurring in the first place, TDU 

Systems contend that transmission providers should be required, as a condition of being 

able to impose penalties, to use software designed to identify unreserved uses. TDU 

Systems suggest that such software could disallow tags for service that exceeds reserved 

levels. They argue that the Commission missed the point by rejecting this suggestion in 

Order No. 890 based on the expectation that the reforms adopted would reduce the level 

of unreserved use penalties for instances of inadvertent uses. TDU Systems contend that 

the Commission’s stated objective of discouraging disorderly use of the transmission 

system would be better achieved by requiring the use of software designed to identify 

inadvertent uses, rather than the assessment of steep unreserved use penalties. 

443. TDU Systems further argue that prior Commission approval of penalties should 

have been required, arguing that due process requires nothing less than Commission 

notice, review, and approval, as well as an opportunity for a hearing, before application 

of any unreserved use penalty. TDU Systems argue that the burden should be on the 
Docket No. RM05-17-001, et al. - 233 -

transmission provider to justify any requested penalties, rather than on the transmission 

customer to disprove the reasonableness of a penalty through the complaint process. 

444. TAPS requests clarification of the Commission’s statement that the transmission 

provider is free to use the undesignated portion of a remote network resource to serve its 

bundled retail customers since it does not have to “take service” under its OATT for the 

transmission of power that is purchased on behalf of bundled retail customers. TAPS 

contends that, although a transmission provider is not required to take network service to 

meet the needs of its bundled retail loads, it does have to abide by all of the requirements 

of designating network resources for such purpose172 and that the non-tariff service the 

transmission provider uses for itself must be comparable to the network service provided 

to its transmission customers.173 TAPS argues that the transmission provider’s own use 

of non-designated resources (or portions of resources) to meet bundled retail therefore 

must be on a non-firm basis supported by secondary network service, as is the case for 

network customers.174 TAPS requests rehearing to the extent the Commission intended 

to allow transmission providers preferential use of the transmission system. 

445. TAPS also requests clarification that the Commission’s discussion of secondary 

network service was intended to address only what a network customer (or the 

 172 Citing pro forma OATT section 28.2; Wisconsin Public Power Inc. SYSTEM 

v. Wisconsin Public Svc. Corp., 84 FERC ¶ 61,120 (1998). 

173 Citing pro forma OATT section 28.3. 

174 Citing In re SCANA Corp., 118 FERC ¶ 61,028 (2007); Idaho Power Co., 

103 FERC ¶ 61,182 (2003). 
Docket No. RM05-17-001, et al. - 234 -

transmission provider) can and cannot do with respect to the host transmission provider’s 

system and does not place any limitations on the use of resources on the remote systems. 

TAPS asks that the Commission clarify that the host transmission provider cannot impose 

a penalty for scheduling delivery of designated or undesignated portions of a customer’s 

remote resources when such delivery does not utilize the host transmission provider’s 

transmission system. 

446. Washington IOUs contend that established rules in place since Order No. 888 have 

allowed network customers to use a firm transmission path reserved for a designated 

network resource for any power (including economy purchases) as long as the use did not 

exceed the amount of the firm network reservation. Washington IOUs argue that the 

Commission reversed this long-standing policy by prohibiting the use of a reserved firm 

path for network capacity to deliver power from a non-designated resource, which, in 

turn, improperly and unreasonably devalued network service in comparison to point-topoint service. Washington IOUs contend that whether the megawatts using the reserved 

transmission capacity are coming from a designated network resource or a replacement 

power source is largely irrelevant because this distinction does not affect grid use and 

causes no harm to any other customer so long as the quantity does not exceed the amount 

of the reservation. Washington IOUs state that the Commission places no restrictions on 

the resource used to provide the megawatts flowing over a capacity reserved in a longterm firm point-to-point reservation and that it would degrade the quality of network 

service to impose such restrictions, and associated penalties, on network customers. In 

their view, providing penalties for such uses of the transmission system would provide a 
Docket No. RM05-17-001, et al. - 235 -

windfall to other transmission customers because the circumstances giving rise to these 

penalties cause no harm to other customers. 

Commission Determination

447. The Commission declines to distinguish between intentional and unintentional 

unreserved transmission uses and reiterates that all unreserved uses will be subject to 

operational penalties. We conclude that maintaining penalties for any unreserved use of 

transmission service will create the right incentives for customers to take appropriate 

measures to minimize any unreserved use before it occurs, whether intentional or not. As 

the Commission noted in Order No. 890, any unreserved use of transmission service can 

harm reliability and disrupt the allocation of transmission rights.175 It is therefore 

appropriate to maintain penalties for both intentional and unintentional unreserved uses. 

The Commission was sensitive, however, to the concerns of commenters, determining in 

Order No. 890 that penalties should be based on the period of unreserved use rather than 

the period for which service is reserved, which could be much longer. This penalty 

structure more closely approximates the penalty charge with the impact on the 

transmission system while maintaining the correct incentive for transmission customers 

to take the necessary steps to ensure that they reserve appropriate service. 

448. The Commission continues to believe that it would not be appropriate to exempt 

any class of customers from unreserved use penalties. While we appreciate that 

intermittent resources have limited ability to precisely forecast or control generation 

 175 See Order No. 890 at P 838. 
Docket No. RM05-17-001, et al. - 236 -

levels, they are able to reserve sufficient transmission capacity to deliver their full output 

in the event it is produced, thereby mitigating potential unreserved use penalties. In this 

regard, intermittent resources are no different than any other generator and, thus, 

application of unreserved use penalties is not discriminatory. Exempting these or any 

other type of resource from unreserved use penalties would diminish incentives to reserve 

adequate transmission to deliver the resource’s output, potentially creating reliability 

problems for the transmission provider and discriminating in favor of the resource in the 

allocation of transmission rights. 

449. The Commission also disagrees that imposing unreserved use penalties on 

generators for inadvertent positive generation imbalances is duplicative of imbalance 

charges that may be assessed. As the Commission explained in Order No. 890, 

imbalance charges and unreserved use penalties serve different purposes.176 Imbalance 

charges result from a transmission customer’s failure to schedule adequate capacity for 

energy deliveries, whereas unreserved use penalties result from a transmission customer’s 

failure to reserve adequate capacity for energy deliveries. Even though a transmission 

customer may be assessed charges for both an imbalance and an unreserved use in a 

particular scenario, that is appropriate because the transmission customer has delivered 

energy in excess of what it reserved and scheduled. In that instance, application of an 

imbalance charge in addition to an unreserved use penalty recognizes that the 

 176 See id. at P 837. 
Docket No. RM05-17-001, et al. - 237 -

transmission customer both failed to reserve adequate transmission as well as failed to 

properly schedule its energy deliveries. 

450. We acknowledge, as TDU Systems argue, that imbalance charges contain a 

penalty, above-cost component, but disagree that this alone justifies relieving a customer 

of an unreserved use penalty. As a threshold matter, we note that revenues from 

imbalance charges or unreserved use penalties in excess of the transmission provider’s 

costs or relevant transmission rate are distributed to transmission customers, not retained 

by the transmission provider. More to the point, however, imbalance charges and 

unreserved use penalties are associated with different actions and, as such, are designed 

to compensate the transmission provider for different things, while also providing 

appropriate incentives to transmission customers. We continue to believe that both 

imbalance charges and unreserved use penalties should apply to the extent the customer’s 

reservation and schedule are insufficient. 

451. We also acknowledge that, in certain circumstances, inadvertent unreserved uses 

by an LSE serving load in multiple control areas may be beyond the LSE’s control at the 

moment they occur. This does not mean, however, that penalties should not apply to 

such unreserved uses. Like any customer, the LSE is able to protect itself against 

unreserved use penalties by reserving sufficient capacity. We also reject the argument 

that civil penalties would be unjust and unreasonable on their face if applied to 

inadvertent unreserved uses by an LSE. As with any civil penalties, the Commission will 

consider the facts and circumstances before it when determining whether to impose a 

civil penalty for unreserved use of transmission service. 
Docket No. RM05-17-001, et al. - 238 -

452. As the Commission explained in Order No. 890, we will not require transmission 

providers to use software designed to identify unreserved uses as a condition of being 

able to impose operational penalties.177 It is the obligation of the transmission customer, 

not the transmission provider, to ensure that the customer has reserved the transmission 

service that it uses. Moreover, we do not have sufficient evidence before us now to 

decide that, as a general matter, development and implementation of such software would 

be more appropriate than assessing penalties for inadvertent unreserved uses, which we 

note were significantly reduced by the reforms adopted in Order No. 890. For the same 

reasons expressed in Order No. 890, we reject TDU Systems’ argument that Commission 

approval is required prior to assessing an unreserved use penalty.178

453. With regard to TAPS’ concern about the transmission provider’s use of the system 

to serve native load, Order No. 890 did not disturb the requirement from Order No. 888 

that transmission providers serving native load must designate network resources and 

load. Although transmission providers are not required to take service under their OATT 

in such circumstances, we reiterate that, to the extent a transmission provider takes power 

from a non-designated network resource to serve bundled retail load, such power must be 

on a non-firm basis comparable to secondary network service.179 To the extent necessary, 

the Commission clarifies that Order No. 890 was not intended to grant transmission 

 177 See id. at P 835. 

178 See id. at P 836. 

179 See, e.g., Order No. 888 at 31,745. 
Docket No. RM05-17-001, et al. - 239 -

providers greater flexibility than other network customers when using undesignated 

network resources or undesignated portions of designated network resources to serve 

bundled retail load. 

454. We also clarify, as TAPS requests, that the Commission’s discussion of secondary 

network service in Order No. 890 was intended to address only what a network customer 

(or the transmission provider) can and cannot do with respect to the host transmission 

provider’s system.180 The host transmission provider cannot impose a penalty for 

scheduling delivery of designated or undesignated portions of a customer’s remote 

resources when such delivery does not utilize the host transmission provider’s 

transmission system. Unreserved uses of the host transmission provider’s system can, 

however, be charged an unreserved use penalty, and section 13.4 of the pro forma OATT 

provides that the customer using the unreserved service shall be deemed to have executed 

a service agreement with the host transmission provider to govern that service. To the 

extent necessary, we clarify that all unreserved uses of the host transmission provider’s 

system are to be considered uses of firm point-to-point transmission service, even if the 

customer is taking network service or non-firm point-to-point service for the reserved 

portion of its service. 

455. We disagree with Washington IOUs that a network customer’s use of firm 

transmission capacity reserved for a designated network resource to deliver power from a 

non-designated resource causes no harm to other customers. The Commission has long 

 180 See Order No. 890 at P 839. 
Docket No. RM05-17-001, et al. - 240 -

required network customers to use secondary network service to deliver energy from nondesignated resources to serve network load.181 To allow network customers to use the 

firm transmission capacity reserved for designated network resources in such 

circumstances would unduly preference the network customer over other potential users 

of that firm capacity. In such a case, the transmission customer could avoid potential 

curtailments because the purchased energy is scheduled with a higher curtailment priority 

under NERC guidelines than it would receive had the transmission customer used 

secondary network or non-firm point-to-point transmission service.182 In addition, the 

transmission customer uses service that would have potentially been unavailable if it had 

requested service as required. 

(2) Penalty Rate for Unreserved Use of Transmission Service

456. The Commission determined in Order No. 890 that it will continue giving 

transmission providers discretion in setting their unreserved use penalty rates to the 

extent they are consistent with that order. If a transmission provider elects to charge 

unreserved use penalties, the Commission explained that such penalty charges must be 

based on the period of unreserved use rather than the period for which service is reserved, 

subject to certain principles. First, the unreserved use penalty for a single hour of 

unreserved use will be based on the rate for daily firm point-to-point service, even if the 

 181 See pro forma OATT section 28.4; Order No. 888 at 31,748. 

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

118 FERC ¶ 61,026 (2007). 
Docket No. RM05-17-001, et al. - 241 -

transmission provider has a rate for hourly firm point-to-point service on file. Second, as 

a general rule, more than one assessment for a given duration (e.g., daily) will increase 

the penalty period to the next longest duration (e.g., weekly). 

457. The Commission affirmed the requirement that a transmission provider wishing to 

charge unreserved use penalties must explicitly state the penalty rate in its OATT. The 

Commission also retained the current policy established in Allegheny Power Sys., Inc.

that the unreserved use penalty rate may not be greater than twice the firm point-to-point 

rate for the period of unreserved use.183 The Commission established a rebuttable 

presumption that unreserved use penalties no greater than twice the firm point-to-point 

rate for the penalty period are just and reasonable. The Commission further stated that 

transmission providers proposing an unreserved use penalty in excess of twice the 

relevant firm point-to-point rate for pervasive unreserved use could do so in a filing under 

section 205 of the FPA. Transmission providers proposing such a rate must establish that 

a higher penalty rate is required to combat pervasive unreserved use of transmission and 

why the standard rate that penalizes repeated unreserved use is not adequate to 

discourage repeated instances of unreserved use of transmission service. 

Requests for Rehearing and Clarification

458. TDU Systems contend that a 200 percent penalty rate is excessive and unnecessary 

to the extent it is based on periods greater than the unreserved use period. TDU Systems 

argue that, if system integrity and reliability are the bases upon which the penalty policy 

 183 Allegheny Power Sys., Inc., 80 FERC ¶ 61,143 at 61,545-46 (1997). 
Docket No. RM05-17-001, et al. - 242 -

is founded, then penalties for a single hour should be based on the rate for hourly 

transmission service, and so forth. TDU Systems state that that they generally agree that 

a transmission customer must face a penalty in excess of the firm point-to-point rate in 

order to have an incentive to reserve the appropriate amount of service, but contend that 

the Commission fails to justify charging 200 percent penalties on periods greater than the 

unreserved use period. In their view, a 200 percent penalty might be appropriate if based 

only on the period of unreserved use but is excessive and unnecessary when applied to 

periods greater than the unreserved use. 

459. TDU Systems further contend that a 200 percent penalty is excessive in any event 

for an isolated inadvertent use. In their view, the Commission should limit any 

application of the 200 percent penalty charge to intentional or persistent, repeated 

unauthorized uses. TDU Systems claim that the Commission misconstrued this proposal 

in its comments on the NOPR. TDU Systems states that they do not argue that only 

repeated unreserved uses should be subject to a penalty. Rather, they argue that the 200 

percent penalty in particular should apply only to intentional or persistent unauthorized 

uses. 

460. E.ON U.S. maintains that the Commission failed to address whether, or how, a 

transmission provider may recover a penalty from customers whose unauthorized use of 

transmission service also includes unauthorized use of ancillary services. E.ON U.S. asks 

the Commission to clarify that ancillary service rates for unauthorized uses are subject to 

the same price cap (twice the applicable ancillary services rate for the period of 

unauthorized use) and pricing criteria that apply to the unauthorized transmission penalty 
Docket No. RM05-17-001, et al. - 243 -

rates. If not, E.ON U.S. contends that the charge for such unauthorized uses of ancillary 

services will not discourage unauthorized use of ancillary services. 

Commission Determination

461. The Commission affirms the adoption of a rebuttable presumption that unreserved 

use penalties up to two times the transmission provider’s applicable point-to-point service 

rate are just and reasonable. This penalty structure provides appropriate incentives to 

transmission customers to purchase the correct amount of transmission capacity, yet is 

not unduly harsh in light of changes to the definition of the penalty period. Prior to Order 

No. 890, transmission providers could assess unreserved use penalties based on the length 

of the transmission customer’s reservation. The Commission reformed that practice in 

Order No. 890, significantly relaxing unreserved use penalties by requiring that they be 

based on the period of use.184 The Commission balanced the penalty rate of 200 percent 

against that reform, and we continue to believe that the balance struck provides 

transmission customers a just and reasonable incentive to reserve the correct amount to 

transmission capacity. 

 184 See Order No. 890 at P 846. The Commission explained that penalty charges 

must be based on the period of unreserved use, subject to certain principles. First, the 

unreserved use penalty for a single hour of unreserved use will be based on the rate for 

daily firm point-to-point service, even if the transmission provider has a rate for hourly 

firm point-to-point transmission service on file. Second, as a general rule, more than one 

assessment for a given duration (e.g., daily) will increase the penalty period to the next 

longest duration (e.g., weekly). For example, a customer having two unreserved daily 

uses within a week could be charged an unreserved use penalty equal to the weekly firm 

point-to-point rate plus a penalty component up to 100 percent of that weekly firm pointto-point rate, for a total unreserved use penalty charge up to 200 percent of the point-topoint weekly rate. 
Docket No. RM05-17-001, et al. - 244 -

462. It is therefore appropriate to apply the 200 percent penalty rate to all unreserved 

uses, whether inadvertent or intentional. As explained above, all unreserved uses have 

the potential to impair reliability and disrupt the allocation of transmission rights and, 

therefore, all should be subject to a penalty. Underlying TDU Systems’ request for 

rehearing on this point is an apparent belief that persistent unauthorized uses should be 

subject to higher penalties to distinguish them from inadvertent uses. In response, we 

note that the penalty structure adopted in Order No. 890 already provides for increased 

penalties for persistent unreserved uses since more than one assessment for a given 

duration will increase the penalty period to the next longest duration. To the extent a 

transmission provider believes additional penalties are necessary to prevent pervasive 

unauthorized use, it may make a filing under FPA section 205 to propose such additional 

penalties.185 

463. In response to E.ON U.S., the Commission clarifies that all charges for ancillary 

service costs associated with unreserved uses must be based on the actual costs of the 

ancillary service attributable to the unreserved use, i.e., not subject to the 200 percent 

penalty rate. For example, a transmission customer with one hour of unreserved use may 

be charged for one hour of ancillary service costs associated with that use, even if the 

customer is charged twice the daily point-to-point rate for the underlying unreserved use. 

We believe the 200 percent penalty as applied to the firm point-to-point rate based on the 

period of unreserved use is an adequate incentive to accurately schedule without applying 

 185 See id. at P 849. 
Docket No. RM05-17-001, et al. - 245 -

an additional penalty on the related ancillary service charge. If a transmission provider 

wishes to impose charges for ancillary services as a component of an unreserved use 

penalty, the transmission provider must expressly state so in its OATT. 

b. Distribution of Operational Penalties

464. Consistent with its determination regarding the distribution of imbalance penalties, 

the Commission concluded in Order No. 890 that transmission providers must distribute 

all unreserved use and late study penalties they collect, whether from the transmission 

provider’s merchant function or other transmission customers. The Commission required 

that unreserved use penalties be distributed to all non-offending transmission customers, 

whether or not affiliated with the transmission provider (including the transmission 

provider’s native load) and required all late study penalties to be distributed to nonaffiliates. 

465. The Commission required the transmission provider to make an annual 

compliance filing and, in that filing, propose: (1) a mechanism to identify non-offending 

transmission customers; (2) a method to distribute the unreserved use penalty revenues it 

receives to the identified transmission customers; and (3) how it will distribute late study 

penalties to unaffiliated transmission customers. The Commission also required the 

transmission provider to make an annual filing that provides information regarding the 

penalty revenue the transmission provider has received and distributed.186 The 

 186 The annual informational filing must provide: (1) a summary of penalty 

revenue credits by transmission customer; (2) total penalty revenues collected from 

affiliates; (3) total penalty revenues collected from non-affiliates; (4) a description of the 

 (continued...) 
Docket No. RM05-17-001, et al. - 246 -

Commission declined to require the transmission provider to make an annual filing to 

propose a distribution method for unreserved use and late study penalties, concluding 

instead that the annual informational filing requirement was sufficient. 

466. In order to make the transmission provider whole prior to distribution of 

unreserved use penalty revenues, the Commission allows the transmission provider to 

retain the base firm point-to-point transmission service charge and to distribute any 

revenue collected above the base firm point-to-point transmission service charge to all 

non-offending customers. The transmission provider is required to distribute the entire 

amount it pays under section 19.9 of the pro forma OATT for completing service request 

studies on an untimely basis. The Commission also prohibited transmission providers 

from recovering for ratemaking purposes or through any service under the Commission’s 

jurisdiction any amount it or an affiliate pays as an operational penalty. 

Requests for Rehearing and Clarification

467. TDU Systems argue that any retention of revenues from the unreserved use 

penalty by affiliated, non-offending transmission customers will dilute the impact of the 

penalty by returning some of it to the corporate family. While unaffiliated transmission 

customers pay 100 percent of the penalty, TDU Systems contend that affiliated 

transmission customers would pay less than the full operational penalty since some of the 

 

costs incurred as a result of the offending behavior; and (5) a summary of the portion of 

the unreserved penalty revenue retained by the transmission provider. See Order No. 890 

at P 864. 
Docket No. RM05-17-001, et al. - 247 -

costs will be returned to the corporate family. TDU Systems claim that this discount 

constitutes undue discrimination and is inconsistent with comparability. 

468. Claiming that it would be time-consuming and burdensome for a transmission 

provider to refile, on an annual basis, its methodology for assessing and distributing 

operational penalties, Ameren and EEI ask the Commission to clarify that the distribution 

methodology is to be proposed in a one-time compliance filing. In their view, the annual 

informational filing is more appropriately limited to implementation of the distribution 

methodology, i.e., the amount of penalties assessed, the amounts distributed to customers, 

and the amounts retained by the transmission provider. Ameren and EEI suggest that any 

changes to the distribution methodology proposed after acceptance of the one-time 

compliance filing be submitted in a separate filing under FPA section 205. EEI also asks 

the Commission to clarify whether the one-time compliance filing proposing the 

transmission provider’s distribution methodology is to be submitted when the 

transmission provider makes the other tariff modifications to comply with Order No. 890 

or at some other date. 

469. MidAmerican seeks a number of clarifications regarding the requirement to 

propose a distribution methodology in a compliance filing. MidAmerican asks the 

Commission to clarify that the transmission provider must wait for a Commission order 

before commencing the implementation of its filed revenue distribution plan. 

MidAmerican also questions whether it would be acceptable for a transmission provider 

to use the full annual compliance period to identify the non-offending transmission 

customers or, if not acceptable, whether the billing month should be used. MidAmerican 
Docket No. RM05-17-001, et al. - 248 -

suggests that an “offending transmission customer” should be classified as such for the 

entire reporting period and not for a subset of the reporting period. Finally, 

MidAmerican contends that it should be acceptable to allocate the penalty revenues 

between non-offending network customers and point-to-point customers based on the 

total megawatt-hours that each of these customer groups scheduled during the 

compliance period. If the Commission disagrees, MidAmerican seeks clarification of 

how to allocate the penalty revenues between the two customer groups. With regard to 

the annual informational filing, MidAmerican asks the Commission to confirm that it is 

acceptable to submit the annual informational filing some months following the 

compliance filing. MidAmerican also suggests that both the compliance filing and the 

informational filing can be submitted anytime during a calendar year for penalties that 

were imposed during the prior calendar year. 

470. MidAmerican requests further clarification that penalty revenue distribution 

should be treated as credits toward a future billing cycle. MidAmerican also suggests 

that the Commission adopt a reasonable threshold below which penalty revenue 

distributions become disproportionately burdensome, such as any calendar year when the 

total penalties are less than $10,000. Below that threshold, MidAmerican suggests that 

the transmission provider should have the option to make the payment to the transmission 

provider’s regional reliability organization, which it states would contribute to reducing 

payments for reliability that benefits all customers. 
Docket No. RM05-17-001, et al. - 249 -

Commission Determination

471. As some petitioners note, the discussion of the process for distributing operational 

penalties in Order No. 890 is somewhat unclear. We grant rehearing to explain more 

precisely the process transmission providers must follow in filing their unreserved use 

penalty rates, operational penalty distribution methodologies, and annual compliance 

reports with the Commission. 

472. First, if a transmission provider elects to impose unreserved use penalties, it must 

submit to the Commission a tariff filing under FPA section 205 stating the applicable 

unreserved use penalty rate. Second, each transmission provider also must submit a onetime compliance filing under FPA section 206 proposing the transmission provider’s 

methodology for distributing revenues from late study penalties and, if applicable, 

unreserved use penalties. This one-time compliance filing can be submitted at any time 

prior to the first distribution of operational penalties. Transmission providers should 

request an effective date for this distribution mechanism as of the date of the filing and 

may begin implementing the methodology immediately, subject to refund if the 

Commission alters the distribution mechanism on review. The distribution mechanism, 

as accepted by the Commission, will remain effective until the transmission provider files 

changes to the proposed structure or the Commission directs any such changes on its own 

motion. Finally, each transmission provider must report on its penalty assessments and 

distributions in an annual compliance report to be submitted on or before the deadline for 

submitting FERC Form-1, as established by the Commission’s Office of Enforcement 
Docket No. RM05-17-001, et al. - 250 -

each year. This annual compliance report should be filed under in the same docket as the 

docket in which the proposed one-time compliance filing is submitted. 

473. Although we will continue to allow transmission providers to propose a 

mechanism through which they will identify who is a “non-offending” transmission 

customer for purposes of making unreserved use penalty distributions, this should not be 

based on the entire calendar year, as MidAmerican suggests. For instance, for purposes 

of calculating penalty revenue distributions, it would not be appropriate for transmission 

providers to lump together all customers who caused any degree of unreserved use over 

the course of a year into one group and then distribute the penalty revenues to the 

remaining customers. We believe that it is best to consider the remaining details of a 

transmission provider’s distribution mechanism, including the particular period used to 

identify non-offending customers (e.g., quarterly, monthly, etc.), on a case-by-case basis 

on review of the one-time compliance filing proposing the distribution mechanism. 

474. The Commission rejects requests for rehearing of the determination to allow 

revenues for unreserved use penalties to be distributed to all non-offending customers, 

including affiliates. We acknowledge that this may result in the transmission provider 

receiving penalty revenues on behalf of its native load even when its affiliate has been 

identified as offending customers, or vice versa. We nevertheless believe it is a more 

equitable and administratively efficient method for all users of the transmission system 

that are subject to unreserved use penalties to be eligible to receive a portion of 

associated revenues. If the Commission were to distinguish between affiliates and nonaffiliates in this instance, it would follow that transmission customers that are affiliated 
Docket No. RM05-17-001, et al. - 251 -

among themselves, but not with the transmission provider, should also be excluded from 

distributions to the extent one of the customers is offending. Given the complicated 

ownership structures prevalent in the electric industry, in which one company may own a 

small percentage of several companies, determining whether certain transmission 

customers are affiliates would be a time-consuming exercise for the transmission 

provider. 

475. As the Commission stated in Order No. 890, we will require all operational 

penalty revenues to be distributed, with no exception. In the case of unreserved use 

penalties, we require penalty revenues to be distributed to non-offending customers and, 

in the case of late study penalties, we require penalty revenues to be distributed to all 

non-affiliates of the transmission provider. We will therefore deny MidAmerican’s 

request to allow certain thresholds below which transmission providers may distribute 

penalty amounts to third parties such as regional reliability organizations. Such a policy 

could decrease the financial incentive built into the current rule, which rewards nonoffending customers with a portion of the distributed revenues for abiding by 

Commission policies. We recognize, however, that it could be administratively difficult 

for some transmission providers to distribute small amounts of penalty revenues and note 

that transmission providers have flexibility in developing their distribution methodologies 

to minimize administrative burdens, by establishing reasonable minimum thresholds to 

trigger a distribution, provided they do not unduly restrict the distribution of penalty 

amounts. 
Docket No. RM05-17-001, et al. - 252 -

c. Applicability of Operational Penalties Proposal to RTOs 

and Other Independent or Non-Profit Entities

476. The Commission clarified in Order No. 890 that RTOs and independent 

transmission coordinators, like any other transmission provider, are bound by the 

requirement to distribute revenues they receive when they assess operational penalties. 

The Commission declined to exempt non-profit transmission providers from the 

requirement to distribute unreserved use penalties they pay to the extent they take service 

under their own tariffs. If a non-profit transmission provider incurs an operational 

penalty as a result of its activities as a transmission customer, it is required to distribute 

penalties to non-offending customers. 

Requests for Rehearing and Clarification

477. Ameren asks the Commission to clarify that non-profit transmission providers, 

including RTOs, are not liable for any operational penalties. If a penalty is assessed on 

an RTO or non-profit transmission provider, Ameren contends they should not be 

allowed to flow through to their ratepayers the costs of such penalties, regardless of 

whether their affiliates engage in for-profit activities. Ameren contends that allowing for 

such recovery would be inconsistent with Commission policy.187 With respect to RTOs 

in particular, Ameren contends that allowing RTOs to pass through penalties essentially 

punishes companies for participation in an RTO. To the extent a non-profit transmission 

provider is assessed an operational penalty at all, Ameren contends it should only be 

 187 Citing Order No. 890 at P 865; Cleco Corp., 104 FERC ¶ 61,125 at 61,441 

(2003). 
Docket No. RM05-17-001, et al. - 253 -

obligated to pay such penalty to the extent it can do so through any operations in which 

the transmission provider retains any proceeds above its costs, such as wholesale 

marketing operations of the transmission provider or its affiliates. If the Commission 

wishes to sanction an RTO, ISO, or independent system administrator, Ameren argues 

that it should consider different measures, such as reductions in management bonuses. 

478. New York Transmission Owners agree that penalties must be structured so they do 

not flow through to other parties and similarly suggest that penalties be paid through 

items like variable pay or bonus programs. With respect to potential penalties paid by 

NYISO, New York Transmission Owners ask the Commission to require that they be 

paid out of compensation and incentive programs and that the Commission tailor such 

penalties to recognize NYISO’s limited ability to pay them. 

479. NYISO and the ISO/RTO Council, however, object to disallowance of cost 

recovery for operational penalties. They state that the Commission neither generically 

allowed nor disallowed pass-throughs of reliability-related penalty costs in Order No. 672 

and, instead, adopted a case-by-case approach, inviting RTOs and ISOs to make filings 

under FPA section 205 to propose penalty cost recovery mechanisms. They argue that 

the Commission failed to identify any difference between reliability and operational 

penalties that would justify departing from the case-by-case approach adopted in Order 

No. 672. 

480. The ISO/RTO Council argues that use of variable employee bonus funds to pay 

operational penalties would penalize employees for issues beyond their control and 

impair the ability to hire and retain qualified management. It contends the Commission 
Docket No. RM05-17-001, et al. - 254 -

would have no authority under FPA section 316A to impose penalties on particular 

employees for tariff violations of their employer utility. The ISO/RTO Council objects to 

potential personal liability as a violation of due process and an attempt to dictate the 

internal management decisions of a public utility. 

481. NYISO contends that the prohibition on recovering penalty costs in rates is 

inconsistent with the Commission’s Policy Statement on Enforcement,

188 which provides 

that the level of penalties should account for the effect on the financial viability of the 

company that committed the wrongdoing and reasonably reflect the seriousness of an 

offense. NYISO acknowledges that the Commission indicated it would consider 

financial impacts on RTOs and ISOs when deciding whether to assess penalties, but 

argues the Commission erred in assuming that non-profit RTOs and ISOs can somehow 

absorb penalty costs. 

482. NYISO states that the premise underlying the Commission’s decision in Order No. 

890 that RTOs and ISOs have other sources of revenue that could absorb penalty costs is 

flatly incorrect. NYISO explains that it collects revenues for both transmission and nontransmission services (i.e., market administration) through Rate Schedule 1 and that all 

revenues from sources other than Rate Schedule 1 (e.g., interconnection studies, customer 

trainings, and interest earnings) are used to reduce Rate Schedule 1 charges. NYISO 

therefore contends that it has no excess funds available to pay penalties. NYISO states 

 188 Enforcement of Statutes, Orders, Rules, and Regulations, 113 FERC ¶ 61,068 

(2005) (Policy Statement on Enforcement). 
Docket No. RM05-17-001, et al. - 255 -

that it does interpret Order No. 890 to allow it to recover penalty costs through any rates 

and thus questions how a non-profit RTO and ISO could recover those costs. NYISO 

asks the Commission to grant rehearing and allow non-profit RTOs/ISOs to argue, on a 

case-by-case basis, for an opportunity to recover penalty costs or to explain why 

sanctions other than financial penalties should be imposed. 

483. National Grid agrees that the Commission should consider the unique problems 

associated with the non-profit status of RTOs/ISOs in determining the type and treatment 

of penalties applicable to such entities. Absent extraordinary circumstances that warrant 

a monetary penalty for RTOs/ISOs, National Grid argues the Commission should use 

non-monetary penalties in the first instance to address violations by the RTO or ISO. To 

the extent that penalties are imposed, National Grid contends that the RTO or ISO should 

be authorized to pass the costs of such penalties to its customers and that these customers, 

in turn should be authorized to recover the costs of such penalties from their own 

customers. 

Commission Determination

484. The Commission denies rehearing of the decision in Order No. 890 not to 

categorically exempt any class of transmission providers from the potential imposition of 

operational penalties. As we explain in section III.D.4.a., competing internal policies or 

staffing issues could lead an RTO or ISO to treat particular types of requests differently 

notwithstanding their organizational independence from market participants. By 

imposing late study penalties on RTOs and ISOs, the Commission has established 

financial incentives for those transmission providers to complete request studies in a 
Docket No. RM05-17-001, et al. - 256 -

timely manner or otherwise justify their inability to do so. RTOs and ISOs are like any 

other transmission provider in this regard. We will nonetheless take into consideration 

the relative ability of non-profit transmission providers to pay late study penalties on 

review of their notification filings, consistent with the Enforcement Policy Statement.189

485. We acknowledge, as NYISO points out, that non-profit transmission providers 

may not have sources of revenue from which they can absorb late study penalties other 

than revenues collected under a Commission-jurisdictional tariff. As we explain in 

section III.D.4.a., the intent of prohibiting transmission providers from automatically 

passing on to customers the costs of late study penalties was to preclude those 

transmission providers from designing their rates to accommodate a pass through of the 

penalties, i.e., effectively including penalties in its cost of service. The 60-day due 

diligence standard is in place to protect customers and it would therefore be inappropriate 

to automatically recover from those customers penalties assessed for non-compliance. 

An RTO or ISO is permitted to use revenues previously collected under Commissionapproved rates to pay late study penalties by reallocating funds as necessary to distribute 

late study penalty amounts. This does not mean, as the ISO/RTO Council implies, that 

the Commission is imposing personal liability on employees for penalties applied to an 

RTO or ISO. Each RTO and ISO has discretion to determine, as an organization, how to 

reallocate its funds. 

 189 See Policy Statement on Enforcement at P 20 (indicating that assessment of 

penalties should take account of the financial viability of the offender). 
Docket No. RM05-17-001, et al. - 257 -

486. We decline to state generically which particular sources of funds should be used to 

pay late study penalties, since that question would best be answered on a case-by-case 

basis. If the RTO or ISO is unable to identify any appropriate funds from which to pay a 

late study penalty, the Commission will consider case-specific cost-recovery proposals 

under FPA section 205, provided they do not allow for automatic pass-through of 

penalties applied to the RTO or ISO. 

5. “Higher of” Pricing Policy

487. In Order No. 890, the Commission did not address proposals to change or clarify 

the “higher of” pricing policy and, instead, addressed only the narrow issue of whether 

changes to the pro forma OATT are necessary to ensure that, consistent with the “higher 

of” policy, incremental cost transmission rates are presented as monthly rates for 

service.190 Rather than quoting incremental costs as monthly rates, the Commission 

noted that some transmission providers had been quoting incremental rates as lump sum 

payments, a practice that is inconsistent with our ratemaking policy. In Order No. 890, 

the Commission concluded that changes to the pro forma OATT are not needed to 

address this matter. The Commission explained that the transmission provider must 

 190 Order No. 890 at P 884. In Order No. 888, the Commission stated that system 

expansions should be priced at the higher of the embedded cost rate (including the 

expansion costs) or the incremental cost rate, consistent with the Transmission Pricing 

Policy Statement. See Inquiry Concerning the Commission’s Pricing Policy for 

Transmission Services Provided by Public Utilities Under the Federal Power Act, Policy 

Statement, 59 FR 55031 at 55037 (Nov. 3, 1994), FERC Stats. & Regs. ¶ 31,005 at 

31,146 (1994), order on reconsideration, 71 FERC ¶ 61,195 (1995) (Transmission Pricing 

Policy Statement). 
Docket No. RM05-17-001, et al. - 258 -

continue to include a proposed monthly incremental rate with its offer of service 

whenever it proposes to charge the customer an incremental rate. The transmission 

provider must also provide cost support for the derivation of the rate consistent with the 

cost support that the transmission provider would provide to the Commission in a section 

205 rate filing. 

Requests for Rehearing and Clarification

488. EEI requests clarification that transmission providers may calculate the 

incremental costs of network upgrades so as to allow incremental rates to vary over the 

term of the contract to reflect changes in the transmission provider’s cost of service. 

While recognizing that the Commission declined to grant this clarification in Order No. 

890, EEI believes that this clarification will enhance compliance with the Commission’s 

policies and is therefore within the scope of this proceeding. 

489. Great Northern seeks rehearing of the Commission’s decision not to require 

transmission providers to permit a customer to opt for a longer contract term (to obtain a 

longer amortization period and a lower rate) once the incremental cost of transmission 

upgrades has been determined. Great Northern argues that failure to grant this option 

will result in uncertainty and delay in the development of competitive generation 

resources. Great Northern claims that there is no record evidence that adopting its 

request would be problematic for any transmission provider, customer, or market 

participant. Great Northern contends that, if an increase in contract term would trigger a 

need for additional, or different, upgrades, it would be the responsibility of the 

transmission customer to pay for those upgrades over the term of the contract. 
Docket No. RM05-17-001, et al. - 259 -

490. If the Commission does not allow general flexibility for transmission customers to 

adjust the term of their requested transmission service contract to provide a longer period 

for amortizing the costs of system upgrades once the incremental cost of expansion is 

disclosed by the transmission provider, Great Northern requests the Commission to allow 

contracts to be extended in the specific circumstances where pending transmission 

service requests were made for one year (or longer if necessary to pay for any required 

system upgrades) and the transmission provider is on notice of the potential need for a 

longer contract term. Great Northern states that it has made twenty-three transmission 

service requests on transmission provider systems which are currently being studied, and 

in each instance the request was made for a one year term or longer if necessary to pay 

for any required system upgrades. 

 Commission Determination

491. We continue to believe that the specific pricing proposal suggested by EEI is 

outside the scope of this proceeding, as the NOPR and Order No. 890 addressed only the 

narrow issue of whether changes to the pro forma OATT are necessary to ensure that 

incremental cost transmission rates are presented as monthly rates for service. As the 

Commission explained in Order No. 890, such issues are best addressed on a case-bycase basis in particular rate proceedings. We note, however, that the capital costs of 

upgrades, as estimated in a facilities study, and eventually specified in a service 

agreement through an incremental rate, are not subject to change once the customer has 

executed the service agreement. It would not be appropriate to vary capital costs over the 

term of such contracts. 
Docket No. RM05-17-001, et al. - 260 -

492. Great Northern presents no new arguments or information on rehearing that cause 

us to revisit the decision not to require the transmission provider to permit the customer 

to opt for a longer contract term once the incremental cost of the upgrades has been 

determined. The Commission explained in Order No. 890 that the specific upgrades 

required to provide the requested transmission service may depend on the time period 

over which the service is provided. Allowing the customer to opt for a longer contract 

term may therefore trigger a need for additional, or different, upgrades. If this were to 

happen, there would be disruption of the study process and costs could increase. 

493. Additionally, such changes could undermine the fundamental first-come, firstserved aspect of long-term transmission service. Order No. 888 provided for long-term 

firm point-to-point transmission service on a first-come, first-served basis.191 

Lengthening the term of a contract once the incremental costs of upgrades is determined 

would be a material change to the original transmission service request, voiding the 

original request and creating a new request. Allowing a customer to lengthen its contract 

term as Great Northern suggests could allow the transmission customer to supersede 

another eligible customer’s first-in-time claim to future transmission service in violation 

of Order No. 888. The fact that the transmission customer would be responsible for 

paying for any additional upgrades, or the possibility that development of competitive 

generation could be delayed, does not address the potential uncertainty and chaos that 

 191 See pro forma OATT section 13.2. 
Docket No. RM05-17-001, et al. - 261 -

could arise from undermining the first-come, first-served foundation of long-term pointto-point transmission service. We therefore deny rehearing on this issue. 

6. Other Ancillary Services

a. Demand Response

494. The Commission affirmed in Order No. 890 the existing pro forma OATT 

provision that transmission customers may purchase from third parties, or make 

alternative comparable arrangements for the provision of all ancillary services except for 

scheduling, system control and dispatch service, and reactive supply and voltage control 

service. Regarding the sale of other ancillary services, the Commission clarified that the 

sale of such services by load resources should be permitted where appropriate on a 

comparable basis to service provided by generation resources. The Commission 

modified Schedules 2, 3, 4, 5, 6, and 9 of the pro forma OATT to make clear that reactive 

supply and voltage control, regulation and frequency response, energy imbalance, 

spinning reserves, supplemental reserves and generator imbalance services, respectively, 

may be provided by non-generation resources such as demand resources where 

appropriate. 

Requests for Rehearing and Clarification

495. E.ON U.S. asks the Commission to clarify on rehearing that, for purposes of 

providing reactive supply and voltage control service, non-generation resources only 

include dynamic resources. Without such a clarification, E.ON U.S. contends that 

capacitors added in big blocks could claim to be resources capable of providing reactive 

power, even though such resources only supply VARS and would need to be properly 
Docket No. RM05-17-001, et al. - 262 -

sized and located in order to provide effective reactive capability. E.ON U.S. also argues 

that “non-generation sources” must be a controllable resource, i.e., a resource that a 

transmission provider can connect to via an automatic signal, to be followed 

automatically and immediately by the resource within a time period that is useful for 

providing reactive power. 

496. E.ON U.S. requests further clarification that, for regulation and frequency 

response service, the non-generation resource must be able to match and follow the 

corresponding generation resource provider instantaneously, in the same manner that 

generation resources now provide this service for load. If the non-generation resource 

does not have this capability, E.ON U.S. contends that the transmission system could be 

placed in jeopardy and the transmission provider could be subject to potential reliability 

penalties. 

497. Southern asks the Commission to confirm that demand response resources should 

satisfy the same reliability criteria for providing ancillary services as are required of 

generation resources. Specifically, Southern argues that such resources must meet 

regional reliability council requirements and, if no such requirements have been 

formalized, balancing authority requirements for the qualification of such resources, so 

long as those qualification requirements are not unduly discriminatory. Southern 

contends the Commission’s focus in Order No. 890 on the capability of demand resources 

to provide ancillary services may not take into consideration qualification of those 

resources under non-discriminatory, reliability-based criteria. 
Docket No. RM05-17-001, et al. - 263 -

498. Southern also notes that transmission providers have a certain degree of discretion, 

within the bounds of applicable criteria, to determine the quantity, mix and distribution of 

resources held to provide various system reliability functions. Southern states, for 

example, that it holds and maintains reserves from the lowest-cost resources available for 

that purpose. Southern requests clarification that transmission providers are under no 

obligation to purchase from non-generation resources on a non-economic basis relative to 

otherwise comparable generation resources or to some how discriminate in favor of nongeneration based resources. 

Commission Determination

499. The Commission affirms the decision in Order No. 890 that the sale of ancillary 

services by load resources should be permitted where appropriate on a comparable basis 

to service provided by generation resources. A transmission provider may impose 

appropriate technical criteria, comparable to the requirements placed on generation 

resources, in order to reliably allow load resources to provide the different ancillary 

services. We note that such criteria and requirements have been implemented in RTO 

markets that allow demand response to participate as an ancillary service resource.192 As 

Southern suggests, any such reliability-based qualification criteria should be developed 

 192 PJM, for example, allows load resources to provide regulation service, but 

requires telemetering ability and pre-certification to show the resource can meet the 

physical characteristics in order for the resource to qualify. To participate in the 

synchronized reserve market in PJM, demand response resources must install 

infrastructure such that they can curtail consumption within ten minutes and also must 

provide metering information needed to account for their response. 
Docket No. RM05-17-001, et al. - 264 -

and imposed on a non-discriminatory basis. We also agree with Southern that 

transmission providers should give comparable, not preferential, consideration of load 

resources in selecting the mix of resources to supply ancillary services. 

b. Pricing and Procurement of Reactive Power

500. The Commission rejected requests to modify requirements regarding the provision 

and pricing of reactive power. The Commission reiterated the policy stated in Order No. 

2003, et al., that interconnection customers must be treated comparably with the 

transmission provider and its affiliates in terms of reactive power compensation.193 If the 

transmission provider pays its own generators or those of its affiliates for reactive power, 

then the transmission provider also should pay interconnecting generators for providing 

reactive power within the specified range.194 The Commission stated that it would 

continue to resolve compensation issues for reactive power to qualifying generators on a 

case-by-case basis.

 193 See Standardization of Generator Interconnection Agreements and Procedures, 

Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 31,146 (2003), 

order on reh’g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. 

¶ 31,160 (2004), order on reh’g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), FERC 

Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003-C, 70 FR 37,661 (Jun. 

30, 2005), FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom. National Association of 

Regulatory Utility Commissioners v. FERC, No. 04-1148, 2007 U.S. App. LEXIS 626 

(D.C. Cir. Jan. 12, 2007). 

194 Citing Order No. 2003-B at P 119. 
Docket No. RM05-17-001, et al. - 265 -

Requests for Rehearing and Clarification

501. E.ON U.S. requests that the Commission commence a separate rulemaking to 

address the conflicts that continue to arise regarding reactive power. E.ON U.S. argues 

that the Commission should provide the proper incentives for locating resources to 

provide the maximum benefit in terms of reactive power, and that consumers should not 

be forced to pay for reactive power for units that provide no benefit in terms of reactive 

capability. E.ON U.S. contends it is inappropriate to compensate units for reactive power 

unless they are built in a location where reactive power output is desirable from an 

engineering standpoint and are available in the time period needed in order to be useful to 

the system. E.ON U.S. contends that initiating a rulemaking to consider the locational 

requirements for reactive power payments would ensure a good supply of reactive power 

and reduce the amount of time-consuming and wasteful litigation. 

Commission Determination

502. We again decline the request to initiate a separate rulemaking process to address 

issues regarding compensation for reactive power. The Commission does not believe that 

acting generically on pricing for reactive power is necessary at this time. As the 

Commission explained in Order No. 890, we will continue to resolve compensation 

issues for reactive power to qualifying generators on a case-by-case basis.195

 195 See Order No. 890 at P 898. 
Docket No. RM05-17-001, et al. - 266 -

c. Operating Reserves 

Requests for Rehearing and Clarification

503. Sempra Global contends that the Commission failed to address its comments 

requesting clarification that transmission providers are obligated to offer and make 

available operating reserves to a generator located within the transmission provider’s 

control area, even if the generator-customer is serving load outside of the transmission 

provider’s control area. Sempra Global states that various transmission providers within 

the WECC interpret the requirement to provide operating reserves to customers serving 

load within the control area differently. Sempra Global explains that some in the WECC 

have argued that power cannot be sold as firm unless it includes operating reserves and 

that the current calculation of operating reserve requirements for WECC control area 

operators includes a netting of firm imports and exports. 

504. As a result, Sempra Global argues that transmission providers that operate control 

areas are able to effectively shift portions of their operating reserve requirements by 

contracting for firm power from other control areas, provided that the selling control area 

carries additional operating reserves for the sale. Sempra Global contends that this limits 

the abilities of generators to make firm power sales to entities outside the control area in 

which the generator is located. Sempra Global also argues that this practice allows the 

transmission provider to thwart competition from non-utility generators by limiting the 

ability of merchant generators to make firm power sales outside of the control area. 

Sempra Global asks the Commission to clarify that transmission providers are obligated 
Docket No. RM05-17-001, et al. - 267 -

to offer and make available operating reserves regardless of where the merchant 

generation-customer is serving load. 

Commission Determination 

505. We disagree with Sempra Global that the transmission provider should be 

obligated to offer and make available operating reserves under Schedules 5 and 6 of the 

pro forma OATT when transmission service is used to serve load outside the transmission 

provider’s control area. Operating reserves are needed to serve load within the control 

area in the event of system contingencies. Unless alternative arrangements are made, the 

transmission provider provides these reserves from its own resources. It would be 

inappropriate to require the transmission provider to use its resources to provide 

additional operating reserves to loads in other control areas because the transmission 

providers in those control areas are under their own obligation to make operating reserves 

available. 

506. We therefore conclude that the existing requirements of the pro forma OATT are 

sufficient to ensure that operating reserves are available to serve the type of transaction 

discussed by Sempra Global. A generator serving load outside the control area can make 

alternative comparable arrangements to provide reserves on behalf of its load by 

contracting with third parties. The generator could also request, as part of its negotiation 

with a customer, that the customer acquire reserves from its transmission provider as 

necessary to support the transaction. Modification of the pro forma OATT is not 

necessary to enable generators to engage in firm power sales to loads outside of their 

control area. 
Docket No. RM05-17-001, et al. - 268 -

D. Non-Rate Terms and Conditions

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

507. In Order No. 890, the Commission concluded that the methods for evaluating 

requests for long-term point-to-point transmission service may not be comparable to the 

manner in which transmission service is planned for bundled retail native load and, 

therefore, may no longer be just, reasonable and not unduly discriminatory. To remedy 

this potential for undue discrimination, the Commission amended the pro forma OATT to 

require transmission providers, other than most RTOs and ISOs, to offer a modified form 

of planning redispatch as well as a conditional firm option to long-term point-to-point 

customers. A number of petitioners have requested rehearing of the Commission’s 

decision to modify the planning redispatch requirements and institute a new obligation to 

offer the conditional firm option. We first address the threshold requirement to offer 

these options and then turn to implementation of each option. 

a. Requirement to Offer Planning Redispatch and 

Conditional Firm 

508. The requirement to offer planning redispatch was adopted in Order No. 888 under 

section 19.3 of the pro forma OATT. Transmission providers were required to identify, 

in each system impact study, system constraints as well as redispatch options available to 

resolve those constraints and provide planning redispatch to the extent redispatch was 

more economical than the cost of transmission upgrades. In Order No. 890, the 

Commission modified the planning redispatch requirement, adding specificity to the 

information required in the system impact study and limiting planning redispatch to an 
Docket No. RM05-17-001, et al. - 269 -

option that is reassessed every two years if the customer chooses not to pay for upgrades. 

The Commission also removed the limitation of offering planning redispatch only when it 

is more economical than the cost of transmission upgrades. The Commission rejected 

arguments against the underlying requirement to offer planning redispatch as collateral 

attacks on Order No. 888. 

509. The Commission also found that transmission providers were using a service 

analogous to the conditional firm option, in addition to planning redispatch, to serve their 

own loads. The Commission concluded that transmission providers must evaluate 

transmission availability to serve long-term firm point-to-point service requests in a 

manner that is comparable with the method used to evaluate their own transmission needs 

and to integrate their resources to serve bundled retail native load. The Commission 

therefore required non-ISO/RTO transmission providers to make available both the 

planning redispatch and conditional firm options to long-term firm point-to-point 

customers. The Commission emphasized, however, that transmission providers are not 

required to offer either the planning redispatch or conditional firm option if doing so 

would impair the transmission provider’s ability to reliably serve other firm customers, 

including native load and network customers. 

510. The Commission also placed several limitations on the nature of the planning 

redispatch and conditional firm options to limit the their potential impact on reliability. 

First, the Commission required that the planning redispatch and conditional firm options 

be made available to long-term point-to-point customers. While a transmission provider 

might choose to propose planning redispatch or conditional firm on a shorter-term basis, 
Docket No. RM05-17-001, et al. - 270 -

it would not be required to under the pro forma OATT. Second, the Commission 

distinguished between two different types of customers that may request the service: 

customers who support the construction of upgrades and those who do not. For 

customers supporting the construction of upgrades, the planning redispatch or conditional 

firm options need only be offered until the time when the upgrades are constructed. The 

conditions or redispatch applicable to the interim period must be specified in the service 

agreement and will not be subject to change. For customers choosing not to support the 

construction of new facilities, the planning redispatch or conditional firm options must be 

made available as a reassessment product, i.e., subject to reassessment every two years by 

the transmission provider. Every two years, or sooner if at the continuation of the term of 

service, the transmission provider must reassess the redispatch required to keep the 

service firm or the conditions or hours under which the transmission provider may 

conditionally curtail the service.196 

511. With regard to transmission service provided by RTOs and ISOs, the Commission 

found that it would be inappropriate to require RTOs and ISOs with real-time energy 

markets to adopt the provisions for conditional firm point-to-point service. The 

Commission explained that customers transacting in RTOs and ISOs are able to buy 

 196 The Commission acknowledged that some transmission providers may be able 

to provide conditional firm service over a period longer than two years without the need 

for reassessment. In the event a transmission provider is able to extend the assessment 

period, the Commission stated that waiver or extension of the right to reassess the 

availability of the option would be permitted, provided that the waiver or extension is 

provided consistently for all similarly situated service. 
Docket No. RM05-17-001, et al. - 271 -

through transmission congestion in the real-time energy markets and need no prior 

reservation in order to access transmission. The Commission did require, however, 

RTOs and ISOs that already provided planning redispatch pursuant to section 13.5 of the 

Order No. 888 pro forma OATT to modify the relevant provisions of their tariffs 

consistent with the directives of Order No. 890.197 RTOs and ISOs not already providing 

planning redispatch were not required to amend their tariffs to include the planning 

redispatch option. 

512. The Commission declined to adopt the conditional firm option for network service 

and made no changes to the planning redispatch provisions for network customers. 

 (1) Planning Redispatch

Requests for Rehearing and Clarification

513. Several petitioners object to the requirement that transmission providers offer 

planning redispatch point-to-point service.198 They argue that the planning redispatch 

requirement can degrade the quality of service to existing firm customers by increasing 

loop flow and creating reliability problems or by shifting costs to them. They argue that 

planning redispatch increases curtailment risks to existing customers because generators 

are used in a manner that is different than the planned use of those generators. Ameren 

argues that planning redispatch is unduly discriminatory in that it requires the use of the 

 197 The Commission explained such modification would include the transmission 

provider’s obligation to post monthly redispatch costs for each transmission facility over 

which planning and reliability redispatch are provided. 

198 E.g., Ameren, NRECA, and TDU Systems. 
Docket No. RM05-17-001, et al. - 272 -

transmission provider’s generation resources but not the resources of network customers 

or third parties. Ameren also argues that planning redispatch is not superior to the 

options already in place in the pro forma OATT adopted in Order No. 888. Other 

petitioners assert that the modifications to planning redispatch will remove incentives for 

transmission expansion because planning redispatch will always be cheaper and easier for 

customers than paying for new transmission capacity.199 

514. Several petitioners argue that the merits of commenter arguments on planning 

redispatch should be addressed rather than rejected as collateral attacks against Order No. 

888.200 Ameren asks the Commission to revisit the requirement imposed in Order No. 

888 to provide planning redispatch to point-to-point customers as the Commission 

revisited all Order No. 888 requirements in Order No. 890. E.ON LSE asserts that 

arguments about the reliability impacts of the planning redispatch service are not barred 

as collateral attacks because the Commission changed the service by removing the 

expansion price cap. E.ON LSE states that by removing the expansion cap the 

Commission placed a burden on transmission providers to provide planning redispatch 

even if it would be more costly than the construction of transmission upgrades. 

515. Ameren and Southern reiterate concerns that modeling of planning redispatch will 

be challenging given the difficulty of projecting redispatch costs and the availability of 

generating units, even if the projections are limited to a two-year period. Ameren expects 

 199 E.g., E.ON LSE, NRECA, and TDU Systems. 

200 E.g., Ameren, E.ON LSE, and Southern. 
Docket No. RM05-17-001, et al. - 273 -

that it may deny service on reliability grounds for every request. Given this expectation, 

Ameren argues that the Commission should develop clear reliability guidelines so that 

transmission providers can comply without subjecting themselves to claims of 

discrimination for denying service. E.ON LSE states that projecting redispatch costs will 

be difficult and likely result in inaccurate estimates. 

516. Other petitioners express concern that a transmission provider may avoid its 

obligation to provide planning redispatch or conditional firm service by rejecting requests 

based on an arbitrary, unreasonable and conservative definition of reliability.201 

Constellation states that oversight is necessary to ensure that transmission provider 

conclusions are sufficient to demonstrate that planning redispatch options were properly 

considered. EPSA supports publicly posting on OASIS reserve margin measures to 

eliminate the inflation of margins exceeding reliability requirements. Williams 

recommends adoption of a reliability standard to ensure the options are not improperly 

rejected on reliability grounds. 

517. Ameren argues that the Commission should grant a blanket exemption from the 

planning redispatch requirement for all RTOs because: RTO markets are independent; 

RTOs do not own or operate generation; and the redispatch requirement could exacerbate 

seams issues and affect the calculation and distribution of financial transmission rights 

(FTRs). Ameren expresses concern that the planning redispatch requirement will also 

adversely impact the calculation of the revenue sufficiency guarantee charges in MISO. 

 201 E.g., Constellation, EPSA, and Williams. 
Docket No. RM05-17-001, et al. - 274 -

518. Several petitioners contend that the obligation to provide the planning redispatch 

option contradicts section 217 of the FPA to the extent it impinges on native load 

service.202 South Carolina E&G argues that requiring transmission providers to offer 

planning redispatch could marginalize native load, in violation of section 217, unless the 

Commission modifies section 13.6 of the pro forma OATT to eliminate comparable 

curtailment of native load and non-native load service. South Carolina E&G contends 

that the Commission is precluded under section 217(k) from making a finding that it is 

unduly discriminatory if practices governing the evaluation of long-term firm point-topoint service are not comparable to the manner in which transmission service is planned 

for bundled retail native load. South Carolina E&G contends that recognition of the 

curtailment primacy of native load service would provide a necessary escape mechanism 

should the planning redispatch or conditional firm options threaten native load service. 

South Carolina Regulatory Staff objects to the planning redispatch and conditional firm 

options to the extent that native load purchasers of electricity are required to bear the 

costs of additional transmission capacity necessitated by transmission to non-native 

consumers. 

519. E.ON LSE also argues that FPA section 217 prohibits requiring transmission 

providers to offer native load redispatch to non-native load customers on the basis of 

claimed discrimination. E.ON LSE asks the Commission to clarify that, in real time, 

 202 E.g., E.ON LSE, South Carolina E&G, South Carolina Regulatory Staff, and 

Southern. 
Docket No. RM05-17-001, et al. - 275 -

LSEs may use all or a portion of their resources to serve native load rather than 

redispatch for third parties. E.ON LSE also requests clarification that the generation 

facilities having restricted run times may be reserved for the use of native load needs and 

not be offered for firm point-to-point planning redispatch service. 

520. NorthWestern requests that the Commission grant waiver of the redispatch 

requirements for transmission providers who do not have the ability to dispatch 

generation. Washington IOUs request Commission clarification that when a viable, 

parallel path is available to a transmission customer to move its power, the transmission 

provider is not required to offer planning redispatch service. Washington IOUs state that 

in the Pacific Northwest transmission customers may be able to move power to the same 

point more easily by purchasing transmission service over a neighboring transmission 

system. Washington IOUs argue that in such a situation requiring a jurisdictional utility 

to offer planning redispatch service would unreasonably increase the costs of providing 

transmission service. 

521. Washington IOUs further argue that the Commission erred in not exempting 

hydro-based systems from the planning redispatch requirements. Washington IOUs 

argue that the Commission failed to recognize that hydro units may not be available due 

to recreational, flood control, fish mitigation and other non-power related requirements. 

Washington IOUs further assert the Commission should exempt hydro-based systems 

from providing planning redispatch because of possible occurrence of pricing disputes, 

under-recovery of costs, and disputes over study of planning redispatch opportunities. 
Docket No. RM05-17-001, et al. - 276 -

522. TAPS asserts that the Commission failed to revise to insert new planning 

redispatch provisions into pro forma OATT section 32.3 pertaining to network service 

system impact studies. TAPS also argues that the Commission must ensure that 

transmission service provided to network customers is comparable to the service 

transmission providers provide themselves through planning redispatch and low 

granularity system models. TAPS argues that transmission providers use planning 

redispatch combined with their system-wide modeling to designate network resources 

that otherwise might be undeliverable. TAPS asserts they do this by treating their control 

areas as a whole for sink purposes while selectively disaggregating their resources for 

sourcing purposes. TAPS asserts that undue discrimination arises because a network 

customer’s request to bring on new network resources is modeled with granularity, 

without the benefit of planning redispatch and the redispatch assumed by modeling the 

transmission provider’s own load as a single system sink when designating resources. 

TAPS asks the Commission to redress this discrimination by prohibiting the transmission 

provider from denying any request for transmission to a network customer, or requiring 

upgrades or mitigation, the costs of which are not shared on a load-ratio basis, if the 

request would have been accepted if the transmission provider’s own load had been the 

designated sink. 

523. Finally, EEI requests clarification of the length of the service request that would 

qualify for these options. EEI notes that sections 15.4(b) of the pro forma OATT does 

not qualify the provision of planning redispatch only to long-term firm point-to-point 

customers. EEI asks the Commission to amend sections 15.4(b) of the pro forma OATT 
Docket No. RM05-17-001, et al. - 277 -

to make this section consistent with the statements in Order No. 890 providing that a 

transmission provider is obligated to provide planning redispatch service to customers 

requesting long-term firm point-to-point service, but not to customers requesting shortterm firm service. 

Commission Determination

524. The Commission affirms the decision in Order No. 890, originally established in 

Order No. 888, to require transmission providers to redispatch their generation resources 

in certain circumstances to create additional capacity on the transmission grid. 

Petitioners arguing for removal of this requirement have failed to show any actual 

degradation of reliability, degradation of service to other firm customers, or delay in grid 

expansion caused by planning redispatch service during the first 10 years in which the 

requirement was in place. We therefore decline to eliminate this long-standing option for 

point-to-point customers.203

525. We also affirm the limitation placed on the planning redispatch requirement, 

which we believe adequately address petitioners’ concerns regarding potential effects on 

reliability or service quality. The Commission in Order No. 890 scaled back the 

 203 Arguments that the Commission has no authority to impose a planning 

redispach obligation are a collateral attack on Order No. 888. We disagree with E.ON 

LSE’s assertion that removal of the expansion cap placed a new burden on transmission 

providers by fundamentally changing the nature of the service. While Order No. 890 

required planning redispatch to be provided even when it is more expensive than 

transmission upgrades, service is only guaranteed for two years if customers do not pay 

for upgrades. This puts a bound upon the service for transmission providers that benefits 

rather than burdens them. 
Docket No. RM05-17-001, et al. - 278 -

obligation to provide planning redispatch service by severing the link between it and 

transmission upgrades, no longer requiring the provision of planning redispatch for an 

indefinite period.204 Under the modified planning redispatch option, transmission 

customers must agree to pay for transmission upgrades or agree to have the conditions of 

their planning redispatch service reassessed every two years. These modifications more 

appropriately balance customers’ needs with transmission providers’ reliability and 

native load obligations. Planning redispatch service under Order No. 890 is, therefore, 

superior to that service under Order No. 888, contrary to Ameren’s assertions. 

526. We disagree that planning redispatch will remove incentives for transmission 

expansion. As modified in Order No. 890, planning redispatch may provide a means for 

greater transmission investment as customers will be able to receive the bridge service 

prior to the completion of upgrades. The benefit of immediate access to the transmission 

grid could result in more attractive financing and cash flow options for new resources, in 

turn resulting in more investment in transmission. Moreover, customers taking the 

reassessment product may identify over time others willing to jointly fund upgrades, 

leading to further investment. In asserting a negative impact on transmission expansion, 

petitioners imply that planning redispatch will always be a less expensive option than 

investment in upgrades. But if that were true then planning redispatch would have 

proliferated over the last 10 years given that transmission providers were obligated to 

provide planning redispatch if it was more economical than transmission upgrades. 

 204 Order No. 890 at P 926. 
Docket No. RM05-17-001, et al. - 279 -

527. Petitioners’ concerns about harms to existing customers through increases in loop 

flow and curtailment risks are not unique to rights granted through the use of planning 

redispatch. The efficient use of the existing transmission grid, including every 

incremental new firm use, brings with it an increased risk in the instances and megawatt 

quantity of curtailment for all existing users of the grid. As the Commission explained in 

Order No. 890, the modifications to planning redispatch will enable transmission 

providers to better manage the risks of curtailment for current users of the transmission 

grid because the obligation to redispatch will no longer be open-ended.205 We reject 

TDU Systems’ assertion that planning redispatch will increase costs for network 

customers because it is based upon an incorrect assumption that Order No. 890 would 

require transmission providers to redispatch network customers’ resources for point-topoint customers.206 

528. We disagree with NRECA and TDU Systems that planning redispatch service 

increases curtailment risk because generation is used differently than planned. By 

definition, transmission providers must study the resources that they will redispatch in 

order to offer each individual planning redispatch service. Thus, generation will be used 

by transmission providers as planned. While we acknowledge that planning redispatch 

service presents complicated modeling issues, even when limited to a two-year period, 

 205 See id. at P 593 

206 TDU Systems cites to an argument made by NRECA that concerns the 

transparent dispatch advocates’ proposal for inclusive bid-based real-time redispatch. 

NRECA Supplemental, Affidavit at 27. 
Docket No. RM05-17-001, et al. - 280 -

modeling difficulties exist throughout the utility industry. If anything, the modifications 

to the planning redispatch option adopted in Order No. 890 lessen the modeling burden 

by scaling back the planning redispatch requirement. 

529. With regard to loop flows, we agree with NRECA that changing and unpredictable 

loop flows make it more difficult for system operators to understand their systems and 

respond to contingencies properly. We do not agree, however, that planning redispatch 

will have any greater adverse effect on loop flows than the addition of a new generator to 

the grid or the addition of or a change to a firm point-to-point use. The effects of 

planning redispatch service will be studied in a system impact study well before the 

service is provided, like any other proposed firm use of the system. Transmission 

providers will therefore be able to adjust to planning redispatch uses of the system in the 

same way they now adjust to additions of generation and all new or changed firm pointto-point uses. 

530. Planning redispatch service does not unduly discriminate against transmission 

providers by requiring them to use their resources to provide service. The Commission 

does not require the use of network customer and third party resources to provide 

planning redispatch point-to-point service because third parties and network customers do 

not provide the associated transmission service. Third parties or network customers that 

create additional grid capacity by redispatching, such as through a transaction that flows 

counter to the majority of flows on a line, cannot sell the additional transmission capacity 

that they create. A transmission provider using its resources to serve loads on its system 

can however create and sell additional transmission capacity on its system through 
Docket No. RM05-17-001, et al. - 281 -

control of those resources. It is therefore not unduly discriminatory to require the use of 

transmission provider resources to provide planning redispatch to long-term point-topoint customers. 

531. We decline to develop reliability guidelines or standards for implementing 

planning redispatch. The underlying obligation to provide planning redispatch has been 

in place for 10 years without such guidelines. This is not surprising given that each 

transmission system is different and any industry-wide guidelines would necessarily be 

over or under-inclusive. Transmission providers must already comply with those 

reliability standards approved by the Commission and we will not unnecessarily layer 

additional standards upon the transmission providers for planning redispatch or 

conditional firm service. Transmission providers should retain responsibility for 

incorporating reasonable assumptions into their models in order to manage risks. 

532. We do, however, clarify herein additional valid reasons for denying service on 

reliability grounds. We will not require publication of the metrics underlying these 

reliability grounds or, as EPSA requests, identification of reserves set aside for 

customers; these metrics likely contain competitive information or relate to state-imposed 

requirements. If eligible customers believe they have been unreasonably denied 

redispatch or conditional firm service on reliability grounds, they should bring the matter 

to the Commission’s attention through a complaint or other appropriate procedural 

mechanism. Transmission providers can proactively address claims of discrimination 

resulting from denials of planning redispatch (or conditional firm) service by publishing 
Docket No. RM05-17-001, et al. - 282 -

modeling assumptions and free flow of information between the transmission provider 

and potential customers.207 

533. Concerns about a transmission provider’s inability to project redispatch costs are 

misplaced. In Order No. 890, the Commission directed transmission providers to provide 

eligible customers with non-binding estimates of the incremental costs of redispatch.208 

The Commission expects that transmission providers will use due diligence in providing 

the costs estimates, but as with any non-binding estimate they will not be liable for their 

inability to accurately predict future costs. 

534. The Commission grants rehearing of the decision to require RTOs and ISOs to 

modify planning redispatch provisions that remain in their tariffs. The tariffs of many 

RTOs and ISOs were developed to layer energy markets and financial transmission rights 

on top of the existing pro forma OATT physical rights systems. Upon consideration of 

petitioner’s arguments, we conclude it is more appropriate not to disturb these 

developments by requiring changes to the existing planning redispatch provisions stated 

in sections 13.5, 15.4, 19.1 and 19.3 of the pro forma OATT.209

 207 We note that increased information regarding the modeling, data, and 

assumptions used by the transmission provider to calculate ATC and plan the system 

must now be made available under Attachments C and K to the pro forma OATT. 

208 Order No. 890 at P 958. 

209 To the extent an RTO or ISO has already incorporated this new language into 

its OATT in a prior compliance filing, removal of that language is at the RTO’s or ISO’s 

discretion. 
Docket No. RM05-17-001, et al. - 283 -

535. We will not, however, grant RTOs and ISOs a blanket exemption from the 

planning redispatch requirement, as requested by Ameren. RTOs and ISOs that currently 

offer planning redispatch in addition to the redispatch offered through their energy 

markets prior to issuance of Order No. 890 must continue to provide that service.210 

Where such service is offered, customers should not be excluded from accessing the 

service through planning redispatch unless the Commission has previously found or finds 

in the future that such exclusion is consistent with or superior to the provisions of the pro 

forma OATT. The exacerbation of seams issues and disruption of FTR processes are 

issues that we would consider if an RTO or ISO seeks to terminate its existing planning 

redispatch service.211 

536. We also decline to provide a blanket exemption from the planning redispatch 

requirement for transmission providers without generation or the ability to dispatch 

generation. We clarify, however, that transmission providers without the ability to 

 210 For example, although SPP does not own generation, transmission owners 

within SPP retain the obligation through SPP’s Attachment K to use their resources to 

provide planning redispatch for firm transmission service. See Southwest Power Pool 

FERC Electric Tariff Fifth Revised Volume No. 1, Attachment K, section B, Original 

Sheet No. 238 –239 (Effective February 1, 2007). 

211 Ameren’s concern with disruption of MISO’s revenue sufficiency guarantee 

and FTR allocation processes due to implementation of the planning redispatch 

requirement is misplaced. Under MISO’s tariff, the provisions of Module C (Energy 

Markets, Scheduling and Congestion Management) or the ITC Rate Schedule apply if 

redispatch is more economical than constructing transmission upgrades. See Midwest 

ISO Transmission and Energy Markets Tariff, section 13.5. MISO need not change its 

tariff provisions for the management of redispatch through its energy markets because the 

Commission has already accepted them as consistent with or superior to the Order No. 

888 pro forma OATT. 
Docket No. RM05-17-001, et al. - 284 -

dispatch generation cannot reliably provide planning redispatch service and have no 

obligation to procure generation to provide the service. We deny a blanket exemption 

because transmission providers’ situations can change over time so that they gain the 

ability to dispatch generation. 

537. We affirm our decision to not generically exempt hydroelectric-based systems 

from the provision of planning redispatch service. Contrary to Washington IOU’s 

assertion, the Commission took into consideration the fact that hydroelectric units may 

not be available due to recreation, flood control or fish mitigation when it acknowledged 

the “added difficulty of predicting water availability” in hydroelectric systems.212 While 

there is potential for disputes regarding the availability and cost of a hydroelectric unit, 

such disputes are not unusual for other types of units that are equally subject to the 

planning redispatch requirements. 

538. We disagree that the availability of firm transmission service over a parallel path 

on another transmission provider’s system should relieve a transmission provider of the 

obligation to provide planning redispatch. In order to obtain planning redispatch service, 

a customer must agree to and pay for a system impact study, await the results of the study 

and sign a non-conforming transmission service agreement. We would not expect a 

customer to undertake the more complicated process of obtaining planning redispatch if 

the transmission service meeting the customer’s needs is available elsewhere. We 

 212 Order No. 890 at P 948. 
Docket No. RM05-17-001, et al. - 285 -

therefore see no need to limit the availability of planning redispatch service as 

Washington IOUs request. 

539. It is not necessary to amend the curtailment priorities under the pro forma OATT 

in order for the planning redispatch requirement to be consistent with FPA section 217, as 

South Carolina E&G contends. As we explain in section II.B, section 217(b) provides 

certain protections to a specified class of utilities using their firm transmission rights, to 

the extent required to meet their service obligations. The provision of planning 

redispatch does not impair the use of those firm transmission rights, or otherwise 

marginalize native load, notwithstanding the curtailment priorities established in section 

13.6 of the pro forma OATT. As the Commission explained in Order No. 890, there is no 

obligation to offer planning redispatch if it either (i) degrades or impairs the reliability of 

service to native load customers, network customers and other transmission customers 

taking firm point-to-point service or (ii) interferes with the transmission provider’s ability 

to meet prior firm contractual commitments to others. We clarify that this exempts 

transmission providers from providing planning redispatch from resources that are 

expected to provide reliability redispatch in response to constraints. Further, if resources 

with restricted run times are required to meet the reliable service needs of native load, 

including reliability redispatch needs, these resources need not be offered for planning 

redispatch service. The obligation to offer planning redispatch is therefore consistent 

with the requirements of section 217. 

540. Contrary to South Carolina Regulatory Staff’s assertions, native load will not bear 

the costs of additional transmission capacity created through either the planning 
Docket No. RM05-17-001, et al. - 286 -

redispatch or conditional firm options. While the options could lead to the construction 

of more transmission if customers agree to pay for transmission upgrades, during the 

period these services are provided they do not require the construction of transmission 

upgrades. Rather, they are provided by curtailing the customer or redispatching the 

transmission provider’s resources to create long-term firm transmission. Moreover, costs 

otherwise recovered from native load customers are reduced by the additional revenues 

gained by the additional sales of conditional firm and planning redispatch service. 

541. We also disagree that FPA section 217(k) precludes the Commission from finding 

that it is unduly discriminatory for transmission providers to engage in planning 

redispatch to serve native load while refusing to provide comparable service to long-term 

point-to-point customers. The intent of section 217(k) is to preserve the use of certain 

firm transmission rights to the extent required to meet the service obligations of a class of 

specified utilities. The statute thus protects these utilities’ continued use of protected 

firm transmission rights during periods of constraint or emergency, when service might 

not otherwise be available. The transmission provider’s use of planning redispatch (as 

well as conditional firm service) occurs prior to the occurrence of such conditions, when 

the transmission provider decides to bring a new resource onto its system. It is therefore 

unduly discriminatory for the transmission provider to refuse to make planning redispatch 

(or conditional firm service) available to similarly situated customers. Indeed, this 

furthers the intent of FPA section 217 by facilitating the ability of all long-term users of 

the transmission system to meet their service obligations, which the statute defines 
Docket No. RM05-17-001, et al. - 287 -

broadly to include not only service to end-users, but also to distribution utilities serving 

end-users.213

542. We agree with TAPS that Order No. 890 inadvertently failed to make 

modifications to section 32.3 that correspond to the amendments to 19.3 of the pro forma

OATT to provide more information for customers requesting the planning redispatch 

option. We revise section 32.3 to make clear that the information required in a system 

impact study is nearly identical for network and point-to-point customers. We note that 

the amended section 32.3 only requires a transmission provider to provide an estimate of 

costs for the network customer to the extent it has cost data for the relevant network 

customer’s resources. 

543. However, we deny TAPS’ request to address here the granularity of system 

modeling necessary to implement planning redispatch service. The ATC and planningrelated reforms adopted in Order No. 890 will help address TAPS’ granularity issue once 

these reforms are implemented. Transmission providers have been directed to address 

the effect on ATC of designating and undesignating network resources as part of the 

ongoing NERC/NAESB standardization effort.214 To the extent TAPS has concerns 

regarding the modeling of ATC to respond to requests to designate network resources, 

those concerns should be addressed in the first instance through the NERC/NAESB 

 213 See EPAct 2005 sec. 1233(a)(3) (to be codified at section section 217(a)(3) of 

the FPA, 16 USC 824q(a)(3)). 

214 See Order No. 693 at P 1041. 
Docket No. RM05-17-001, et al. - 288 -

process. We make no further changes to the planning and reliability redispatch services 

in the existing pro forma OATT as these services are already provided comparably to 

network customers. 

544. We agree with EEI’s requested change to provide consistency between the pro 

forma OATT and the preamble of Order No. 890. As the Commission stated repeatedly 

in Order No. 890, transmission providers are obligated to provide planning redispatch 

options only to customers requesting long-term firm point-to-point service.215 We amend 

section 15.4(b) of the pro forma OATT accordingly. We also revise sections 19.1 and 

19.3 of the pro forma OATT to make clear that the planning redispatch option is available 

to eligible customers, not just existing transmission customers, as provided in Order No. 

890. 

(2) Conditional Firm

 Requests for Rehearing and Clarification

545. Several petitioners object to the Commission’s decision to require transmission 

providers to offer conditional firm point-to-point service.216 Ameren states that the 

conditional firm option is not superior to the options already available to customers under 

the pro forma OATT adopted in Order No. 888. Ameren contends that the conditional 

firm service options create more discretion and uncertainty in the processing of service 

requests, contrary to the Commission’s stated goal of increasing transparency in the 

 215 See, e.g., Order No. 890 at P 4, 78, and 911. 

216 E.g., Ameren, NRECA, and TDU Systems. 
Docket No. RM05-17-001, et al. - 289 -

provision of transmission service. Ameren expresses concern that ill-defined conditional 

firm service rules could lead to non-compliance and assessment of significant penalties. 

Ameren and NorthWestern argue that, at a minimum, the Commission must provide 

detailed guidelines and limit the discretion of transmission providers in studying 

conditional firm service options. Ameren states that allowing conditional firm 

transmission to be curtailed only during selected events offers less system reliability. 

Ameren and NRECA ask the Commission to limit or remove the obligation to provide 

conditional firm service because maintaining the service will degrade reliability as 

system planners and operators must account for more and varied uses of the system and 

manage increased loadings on the system. If it is not allowed to deny service for the 

degradation of reliability that would occur with every service request involving 

conditional firm, Ameren asks that the Commission develop clear reliability guidelines so 

that transmission providers can comply without subjecting themselves to claims of 

discrimination for denying service. 

546. South Carolina E&G and South Carolina Regulatory Staff contend that the 

obligation to offer the conditional firm option contradicts section 217 of the FPA to the 

extent it impinges on native load service. South Carolina E&G states that granting a 

secondary network service curtailment priority during conditional curtailment periods 

could adversely affect the reliability of native load service in direct violation of section 

217 of the FPA. South Carolina E&G states that native load customers use secondary 

network service for redispatch when the system becomes constrained; therefore, allowing 

increased use of this priority non-firm service by conditional firm service customers will 
Docket No. RM05-17-001, et al. - 290 -

adversely affect native load customers in violation of FPA section 217. South Carolina 

E&G also argues that FPA section 217(k) precludes the Commission from finding that 

the practice of using conditional firm by transmission providers is unduly discriminatory. 

547. MidAmerican requests clarification that transmission providers are not prohibited 

from voluntarily offering the conditional firm option for short-term point-to-point 

service. MidAmerican also requests Commission clarification that Order No. 890 did not 

require transmission providers to submit revised tariff sheets if the transmission providers 

already provide short-term conditional firm service. 

548. Some petitioners ask the Commission to create a conditional firm network 

service.217 TAPS and NRECA contend that limiting the conditional firm option to longterm firm point-to-point service is inappropriate in light of the Commission’s finding that 

transmission providers provide themselves conditional firm network service. TAPS and 

NRECA argue that the Commission has allowed continued discrimination as between 

transmission providers and network customers. TAPS argues that Order No. 890 enables 

transmission providers to continue to designate resources on a conditionally firm basis, 

but denies network customers the same right to do so. 

549. NRECA and TDU Systems also contend that conditional firm network service is 

required to preserve network customers’ ability to access those resources that they are 

able to obtain today through redirect service without being bumped by conditional firm 

point-to-point customers. In their view, conditional firm network service would prevent 

 217 E.g., NRECA, TAPS, and TDU Systems. 
Docket No. RM05-17-001, et al. - 291 -

gaming and hoarding by point-to-point customers through use of conditional firm service 

and achieve parity in flexibility through use of secondary network service. TDU Systems 

assert that the provision of conditional firm network service is essential to ensure that 

network customers can receive the same priority in maintaining transmission access 

rights as those granted to conditional firm point-to-point customers. 

550. NRECA and TDU Systems argue that allowing conditional firm for the import of 

designated network resources but not allowing it for in-control area transactions is 

irrational, creates perverse operational incentives and does not make legal sense. By way 

of example, NRECA states that a resource could be designated to serve load in a 

neighboring control area, but not in the control area in which the resource is located. 

NRECA contends that creation of a conditional firm network service would provide 

additional support to intermittent resources that wish to sell their services in the control 

area in which these resources are located. 

551. Finally, EEI requests clarification of the length of the service request that would 

qualify for these options. EEI notes that sections 15.4(c) of the pro forma OATT does 

not qualify the provision of conditional firm service only to long-term firm point-to-point 

customers. EEI asks the Commission to amend sections 15.4(c) of the pro forma OATT 

to make this section consistent with the statements in Order No. 890 providing that a 

transmission provider is obligated to provide conditional firm service to customers 

requesting long-term firm point-to-point service, but not to customers requesting shortterm firm service. 
Docket No. RM05-17-001, et al. - 292 -

Commission Determination

552. The Commission affirms the decision in Order No. 890 to create a new conditional 

firm option in the pro forma OATT for customers seeking and denied long-term firm 

point-to-point transmission service.218 We reiterate that, like the planning redispatch 

option, transmission providers are not required to provide conditional firm service if 

doing so would impair system reliability. Concerns regarding system reliability have 

thus already been addressed in the design of the conditional firm option. 

553. We disagree with Ameren that the conditional firm option will create more 

discretion and uncertainty in processing of service requests. In Order No. 890, the 

Commission provided a detailed description of the characteristics, requirements and 

implementation of the new option, developed through multiple industry sessions and with 

supplemental comments. Ameren argues that the obligation to offer the conditional firm 

option should be eliminated unless the Commission provides further guidance regarding 

how to study its availability, yet Ameren does not identify the particular details that it 

believes are missing. Even if there is some initial uncertainty in the processing of service 

requests as transmission providers become comfortable with studying the conditional 

firm option, it is more than offset by the reduction in uncertainty faced by eligible 

 218 As stated above, RTOs and ISOs with real-time energy markets are not 

required to offer the conditional firm option. Also, those transmission providers that do 

not provide long-term firm point-to-point service are exempt from providing conditional 

firm point-to-point service. 
Docket No. RM05-17-001, et al. - 293 -

customers whose service requests would otherwise have been rejected for lacking as little 

as one hour of firm service during the year. 

554. We decline to develop reliability guidelines for the provision of conditional firm 

service, as Ameren requests. Each transmission system will have a different ability to 

accommodate varying requests for conditional firm service. As with planning redispatch, 

any guidelines we create would necessarily be over or under-inclusive and either 

jeopardize the reliability of some transmission providers’ systems or unnecessarily 

restrict the amount of conditional firm service that may be offered. Transmission 

providers may determine the amount of conditional firm service that they can reliably 

provide, as long as they do not reject requests from similarly situated customers. 

555. We disagree that requiring transmission providers to offer conditional firm service 

violates FPA section 217. As we explain above, section 217 provides certain protections 

to a specified class of utilities using their firm transmission rights, to the extent required 

to meet their service obligations. By its very nature, conditional firm service will be 

conditional when the transmission provider cannot accommodate additional firm service 

in light of other commitments, including the firm service obligations of LSEs on its 

system or other existing customers. Moreover, transmission providers are not required to 

offer the service if doing so would impair system reliability. The restrictions placed on 

conditional firm service are thus consistent with, and not in contrary to, the requirements 

of FPA section 217. 

556. We also disagree with South Carolina E&G that conditional firm service violates 

FPA section 217 because it will increase the amount and use of secondary network 
Docket No. RM05-17-001, et al. - 294 -

service, in competition with the use of secondary network service by native load. 

Secondary network service, also called priority non-firm service, is a non-firm 

transmission right. Increased use of secondary network service by conditional firm 

customers therefore does not disturb the use of firm rights protected by section 217. 

Similarly, FPA section 217(k) does not preclude our finding that failure to offer the 

conditional firm option is unduly discriminatory since the conditional nature of the 

service is not within the scope of service protected by FPA section 217(b). 

557. We clarify in response to MidAmerican that a transmission provider that provided 

short-term conditional firm service prior to issuance of Order No. 890 need not revise the 

existing tariff provisions relating to short-term firm service.219 A transmission provider 

proposing to add short-term conditional firm service to its OATT must seek approval 

under FPA section 205. In either case, the voluntary provision of short-term conditional 

firm service does not relieve the transmission provider from the obligation to provide 

long-term conditional firm point-to-point service. 

558. We affirm the decision in Order No. 890 not to create a conditional firm network 

service. Network customers may designate network resources any time firm transmission 

is available, and the term of the designation can include periods of less than a year. 

Network customers can also use secondary network service to access resources during 

times when firm service is not available. This flexibility to use designated network 

resources and secondary network service to access undesignated resources already 

 219 See Order No. 890 at P 135, n.106. 
Docket No. RM05-17-001, et al. - 295 -

provides a service that is like conditional firm service that can be used to integrate new 

resources, intermittent or otherwise. 

559. We agree, however, that transmission providers must study the use of automatic 

devices when requested by a network customer in a system impact study. In Order No. 

890, the Commission found that transmission providers employ automatic devices, such 

as special protection schemes, to take resources offline during certain system conditions. 

Comparability requires the study of these automatic devices for network customers 

seeking to designate network resources. We disagree with TAPS that comparability 

further requires the same service as between network customers and point-to-point 

customers. In Order No. 890, the Commission reiterated that network service and pointto-point service were not designed to be identical and, therefore, the rights and 

obligations of each type of customer need not be the same.220 We therefore deny 

rehearing requests to create a network service that is the same as conditional firm pointto-point service, but revise section 32.3 of the pro forma OATT to require the study of 

automatic devices at the request of a network transmission customer. 

560. We acknowledge that conditional firm point-to-point service may have an impact 

on a network customer’s use of secondary network service due to increased use of 

priority non-firm service, but note that the conditional firm option does not reduce the 

availability of secondary network service any more than the use of short-term firm pointto-point service. Conditional firm point-to-point service could not possibly disrupt a 

 220 See id. at P 1093. 
Docket No. RM05-17-001, et al. - 296 -

network customers use of redirect service because network customers may not redirect 

their service,221 as NRECA argues, nor does the conditional firm option disrupt the 

network customer’s use of point-to-point service to secure off-system resources, since 

network customers may take conditional firm point-to-point service if they choose. 

Finally, NRECA’s concerns regarding potential hoarding are based on a mistaken belief 

that customers taking conditional firm service are not charged the long-term transmission 

rate. The Commission made clear in Order No. 890 that customers taking the conditional 

firm option pay the rate for long-term firm point-to-point service.222

561. We agree with EEI’s requested change to provide consistency between the pro 

forma OATT and the preamble of Order No. 890. As the Commission stated repeatedly 

in Order No. 890, transmission providers are obligated to provide conditional firm 

options only to customers requesting long-term firm point-to-point service.223 We amend 

section 15.4(c) of the pro forma OATT accordingly. We also revise sections 19.1 and 

19.3 of the pro forma OATT to make clear that the conditional firm option is available to 

eligible customers, not just existing transmission customers, as provided in Order No. 

890. 

 221 See id. at P 1612. 

222 See id. at P 1047. 

223 See, e.g., id. at P 4, 78, and 911. 
Docket No. RM05-17-001, et al. - 297 -

b. Implementation of Planning Redispatch and Conditional 

Firm

(1) Characteristics of Service

562. The Commission explained in Order No. 890 that the planning redispatch and 

conditional firm options were not services distinct from point-to-point transmission 

service, but rather a modification to the procedures for granting long-term point-to-point 

service and the curtailment priorities for that service. The primary purpose of each 

option is to address the “all or nothing” problem associated with the current procedures 

for requesting long-term point-to-point service. Where a request for long-term point-topoint firm transmission service is made and cannot be satisfied out of existing capacity, 

the transmission provider must, at the request of the customer and in the system impact 

study, identify (i) the transmission upgrades necessary to provide the service and (ii) the 

options for providing service during the period prior to completion of those transmission 

upgrades. If upgrades cannot be completed prior to expiration of the requested service 

term, the transmission provider must, at the request of the customer and in the system 

impact study, identify options for providing the service during the requested term. The 

options studied by the transmission provider must include both planning redispatch and 

conditional firm options. The transmission provider, at its discretion, may study and 

offer a mix of planning redispatch and conditional firm options for a single service 

request. 

563. If the transmission provider determines that planning redispatch or conditional 

firm options are available, the system impact study must identify the following: (i) the 
Docket No. RM05-17-001, et al. - 298 -

system constraints, identified by transmission facility or flowgate, causing the need for 

the system impact study; (ii) additional direct assignment facilities or network upgrades 

required to provide the requested service; (iii) redispatch options, including the relevant 

congested transmission facilities for which redispatch will be provided, the generation 

resources that can relieve those congested facilities, the impact of each identified 

resource on the congested facilities, and an estimate of the incremental costs of 

redispatch; and (iv) conditional firm options, including the annual number of conditional 

curtailment hours and the specific system conditions during which conditional 

curtailment may occur.224 Transmission providers may recover the costs of studying 

these options through the system impact study agreement. 

564. If the customer agrees to take service, the service agreement must specify the 

relevant congested transmission facilities and whether the transmission provider will 

provide planning redispatch, a mix of planning redispatch and conditional firm, or 

conditional firm in order to provide the point-to-point transmission service. For the 

conditional firm option, customers must choose among, and the service agreement must 

specify, either (i) specific system condition(s) during which conditional curtailment may 

occur225 or (ii) annual number of conditional curtailment hours during which conditional 

 224 The Commission did not require a standardized method of modeling the hours 

in which conditional firm point-to-point service would be conditional, although it did 

state addition of a risk factor to their calculation of annual curtailment hours would be 

appropriate to account for forecasting risks. 

225 Acceptable system conditions could include designation of limiting 

transmission elements, such as a transmission line, substation or flowgate. The 

 (continued...) 
Docket No. RM05-17-001, et al. - 299 -

curtailment may occur.226 In situations in which the customer commits to paying the 

costs associated with upgrades necessary to provide the service on a fully firm basis, the 

conditions or hours identified by the transmission provider must remain in effect until 

such time as the upgrades have been completed. For such customers, the service 

agreement must specify the upgrade costs as determined through the facilities study. 

565. Any service agreement that incorporates planning redispatch or conditional firm 

options will be considered a non-conforming agreement and must be filed by the 

transmission provider pursuant to FPA section 205. Transmission providers therefore 

must also file with the Commission any amendments to these service agreements that 

result from reassessments. If a transmission provider proposes to change the redispatch 

or conditional curtailment conditions due to a reassessment, the Commission obligated 

transmission providers to provide the reassessment study to the customer along with a 

narrative statement describing the study and reasons for changes to the curtailment 

conditions or redispatch requirements no later than 90 days prior to the date for 

imposition of these new conditions or requirements. 

 

Commission stated its belief that designation of system load levels, standing alone, would 

not qualify as an acceptable system condition. Load levels would have to be linked to a 

specific constraint or transmission element that is associated with the request for service, 

e.g., load levels in a constrained load pocket. 

226 Although the Commission did not require use of monthly or seasonal caps, it 

encouraged transmission providers to offer them if they can overcome modeling barriers, 

since monthly or seasonal caps would give more certainty to customers regarding the 

particular aspects of their service. 
Docket No. RM05-17-001, et al. - 300 -

566. During non-conditional periods, conditional firm service is subject to pro rata

curtailment consistent with curtailment of any other long-term firm service. During the 

hours or specific system conditions when conditional firm service is conditional, 

conditional firm service share the same curtailment priority as secondary network service. 

In such circumstances, transmission providers will be allowed to curtail only for 

reliability reasons and conditional firm customers during conditional curtailment hours 

will be curtailed only after all point-to-point non-firm customers have been curtailed. If 

the customer selects the annual hourly cap option, the transmission provider will have the 

flexibility to conditionally curtail the customer for any reliability reason during those 

hours, including but not limited to, the system condition(s) identified in the system 

impact study. 

567. The Commission provided that short-term firm service reserved prior to the 

reservation of conditional firm service will maintain priority over conditional firm service 

in the periods when conditional firm service is conditional, i.e., when specified system 

conditions exist or conditional curtailment hours apply. Transmission providers were 

directed to work with NAESB to develop the appropriate communications protocol to 

allow for automatic assignment of short-term firm point-to-point service to conditional 

firm customers to the extent short-term service becomes available. Transmission 

providers need not implement this requirement until NAESB develops appropriate 

communications protocols. 

568. Transmission providers also were directed to work with customers to facilitate the 

use of third party generation, where available, in provision of planning redispatch. To 
Docket No. RM05-17-001, et al. - 301 -

facilitate provision of redispatch service by third parties, the Commission further directed 

transmission providers, working through NAESB, to modify their OASIS sites and 

develop any necessary business practices to allow for posting of third party offers to 

provide planning redispatch. Again, transmission providers were not required to 

implement the new OASIS functionality and any related business practices until NAESB 

develops appropriate standards. 

569. Finally, the Commission recognized that there may be some regional variation in 

the way transmission providers approach the provision of conditional firm service beyond 

the minimum attributes that established in Order No. 890. The Commission directed 

transmission providers located in the same region to coordinate among themselves to 

develop business practices for implementation of the conditional firm service.227 In order 

to allow time for this regional coordination, the Commission directed transmission 

providers to implement these mechanisms and business practices within 180 days after 

the publication of this Final Rule in the Federal Register, or October 11, 2007. 

Requests for Rehearing and Clarification 

570. AWEA argues that the Commission erred in limiting the term of planning 

redispatch and conditional firm services. AWEA contends that longer-term planning 

redispatch and conditional firm services would better meet the needs of customers 

 227 The Commission encouraged participation of non-public utility transmission 

providers in the region and interested transmission customers in the development of these 

business practices, and directed public utility transmission providers to make efforts to 

include these interested parties in their regional coordination efforts. 
Docket No. RM05-17-001, et al. - 302 -

seeking long-term service that are unable to secure transmission upgrades because they 

are uneconomic. If the Commission declines to eliminate temporal limitations on the 

transmission provider’s obligation to offer these services, AWEA asks the Commission to 

extend the reassessment period from two years to five years. AWEA argues that a five 

year reassessment period may allow customers to secure financing and would be 

reflective of a more typical planning horizon. 

571. In contrast, NRECA asks that the Commission not allow planning redispatch or 

conditional firm point-to-point service unless customers agree to pay for transmission 

upgrades. NRECA argues doing so will eliminate the transmission customer’s incentive 

to free-ride on transmission capacity built and paid for by others. Southern requests 

clarification that transmission customers committing to transmission construction have a 

higher priority for the incremental transmission capacity created by their upgrades than 

planning redispatch or conditional firm customers. If this priority is not granted, 

Southern maintains that planning redispatch and conditional customers not willing to 

commit to such construction could firm up their product by waiting for later-queued 

customers to pay for and construct the upgrades. 

572. EEI and Southern argue that bridge customers should also be subject to the 

biennial reassessment when the period for completing upgrades exceeds two years. EEI 

contends that, unlike reassessment customers, bridge customers receive a lower quality of 

service compared to non-bridge customers because the transmission provider makes their 

determinations using the lowest ATC conditions that occur during the entire term of the 

bridge service agreement. EEI argues that the transmission provider therefore 
Docket No. RM05-17-001, et al. - 303 -

incorporates a larger margin of risk into its initial offer of service to the bridge customer 

than would be necessary if it were able to reassess the service biennially. 

573. Constellation and EPSA request clarification that the biennial reassessment is not 

a de novo review of whether or not to provide conditional firm service and, instead, is 

limited to evaluation of the triggering conditions that were identified in the initial 

analysis. EPSA argues that if the transmission provider’s studies show that only one of 

10 key facilities raises reliability concerns that warrant an offer of conditional firm 

service, the transmission provider must be required to plan for and maintain all facilities 

other than the one identified limiting element on an ongoing basis. Otherwise, EPSA 

contends, conditional firm service denigrates into a two year service obligation. 

MidAmerican asks the Commission to confirm that transmission providers can waive 

their rights to reassess planning redispatch and conditional firm service for all similarly 

situated customers. MidAmerican suggests that transmission providers be able to waive 

reassessment rights for customers in areas experiencing infrequent changes, but maintain 

their reassessment rights for other customers in areas that experience frequent changes. 

MidAmerican contends that a transmission provider’s act of waiving the reassessment 

should not be considered an act of discretion that requires an OASIS posting. 

MidAmerican also requests clarification that waiver of one reassessment period does not 

constitute an infinite waiver of reassessment rights. EEI asks the Commission to confirm 

that the transmission customer bears responsibility for the costs of the biennial 

reassessments since they are performed in response to its service request. 
Docket No. RM05-17-001, et al. - 304 -

574. E.ON U.S. expresses concern that, if transmission providers are completely 

divorced from the third-party provided planning redispatch, there may be a negative 

impact on system reliability and ATC. E.ON U.S. requests clarification that the 

reliability coordinator for the transmission system must oversee third-party provision of 

planning redispatch to avoid interference with reliability redispatch. 

575. MidAmerican seeks rehearing of the Commission’s decision to expand the scope 

of the conditional firm option beyond the original NOPR proposal to include curtailment 

based on system conditions. MidAmerican asserts that this expansion assumes that the 

system has a built-in ability to absorb scheduled flow of energy from full utilization of 

firm or network service plus flows from contingent firm service upon an instantaneous 

system contingency until an operator can curtail conditional firm service. MidAmerican 

argues that contingencies on certain systems, such as systems susceptible to rapid voltage 

collapse and cascading outages, can occur before the operator can respond by curtailing. 

576. Some petitioners argue that the transmission provider, not the transmission 

customer, should choose whether conditional firm curtailment will be based on an 

identified system condition or number of annual hours.228 Ameren asserts that a system 

contingency event is not interchangeable with a number of hours limitation because they 

produce vastly different impacts on the system. Ameren and E.ON U.S. contend that 

modeling processes and changes in system conditions provide uncertainty and will hinder 

the transmission provider from specifying accurate curtailable hours. NRECA suggests 

 228 E.g., Ameren, NRECA, and Southern. 
Docket No. RM05-17-001, et al. - 305 -

that the decision of which approach to use should be driven by the results of the 

transmission provider’s studies, local system conditions governing the availability of 

transmission, and a concern for preserving the reliability and value of existing firm 

service. E.ON U.S. asks the Commission to acknowledge that the risk factor associated 

with the number of hours that a customer can be curtailed for conditional firm service 

may be substantial to reflect the possibility of unexpected events such as a car accident, 

hurricane, or ice storm that require curtailment of transmission over a certain path. 

577. EEI argues that the Commission should grant rehearing regarding the curtailment 

priority of conditional firm service during conditional periods. To allow the same 

curtailment priority as secondary network service, EEI asserts, would adversely impact 

reliable service to network and native load customers because these customers use 

“secondary network service in order to serve network loads reliably.”229 Additionally, 

EEI argues that providing a curtailment priority that is below that of secondary network 

service instead of equal to it does not violate the prohibition against undue discrimination 

or impact comparability. 

578. Southern, EEI and Transerv state that there is no automated process in NERC’s 

Interchange Distribution Calculator (IDC) to convert a tag from firm priority to non-firm 

priority in order to accommodate conditional firm service. EEI states that currently the 

only way to modify the curtailment priority reflected on a tag is to cancel the existing tag 

and issue a new one. According to EEI, this affects the quality of service and ultimately 

 229 Citing Order No. 890 at P 1601. 
Docket No. RM05-17-001, et al. - 306 -

causes the customer to incur imbalance charges. Southern, EEI and Transerv encourage 

implementation of uniform tagging business practices developed by NAESB to bring 

greater uniformity to markets. Transerv and EEI also request that the implementation 

deadline be extended to allow time for these modifications. 

579. Southern also argues that the conditional firm service requirements may conflict 

with NERC reliability standards which require the transmission provider to demonstrate 

that its transmission system is planned such that it can be operated to supply projected 

demands and firm transmission services. Southern contends that if conditional firm 

service is modeled in the base case, it will cause overloads under N-1 contingencies 

resulting in the curtailment of firm transactions in contravention of NERC planning 

criteria. Southern asks the Commission to clarify that a transmission provider will not be 

in violation of NERC reliability standards by providing conditional firm service or if so 

that civil penalties will not be imposed for such violations. 

580. TDU Systems ask the Commission to require transmission providers to update 

their rates to reflect the new conditional firm service revenues and to report to the 

Commission annually any revenues from this service. 

Commission Determination

581. The Commission affirms the decision in Order No. 890 to require transmission 

providers to provide planning redispatch and conditional firm service subject to a biennial 

reassessment when transmission customers are unwilling to pay for transmission 

upgrades. We decline to adopt a longer reassessment period or altogether eliminate the 

reassessment feature of these services. There are legitimate circumstances under which a 
Docket No. RM05-17-001, et al. - 307 -

customer may choose not to support system upgrades, including high construction costs 

or a short term of service that does not merit construction. Balanced against these 

customers’ needs are the needs of transmission providers to reliably provide service and 

of other customers to continue using their own firm transmission rights. Adopting a two 

year reassessment period appropriately balances these various interests. 

582. The Commission did not, as AWEA suggests, limit the term of the reassessment 

service. A customer taking planning redispatch or conditional firm service subject to 

reassessment could receive an unlimited term of service, with the transmission provider 

reassessing every two years the redispatch required to keep the service firm or the 

conditions or hours under which the transmission provider may conditionally curtail the 

service.230 

583. We disagree with EEI and Southern that customers supporting transmission 

upgrades should be subject to the biennial reassessment. In Order No. 890, the 

Commission required the specification of unchanging conditions in a transmission service 

agreement for a customer willing to pay for upgrades.231 Customers agreeing to take 

service under this bridge product require certainty because they typically are financing 

and constructing new resources. While we recognize that a transmission provider may 

need to incorporate a larger margin of risk into the analysis of conditions when a 

 230 We clarify in response to EEI that conditional firm and planning redispatch 

customers should pay for the costs of conducting their individual biennial reassessments. 

231 See id. at P 980. 
Docket No. RM05-17-001, et al. - 308 -

customer has agreed to pay for upgrades that will not be brought online for several years, 

we do not believe that this will most often be the case. We require transmission 

providers to study the conditions for bridge service as they would their own use of a 

similar service used prior to the completion of transmission upgrades. Only those 

transmission providers using large margins of risk in evaluating the acquisition or 

construction of their own new resources with long transmission construction lead times 

should apply large margins of risk to the study of the conditional firm service for a 

customer that agrees to pay for upgrades. 

584. We agree with Southern that customers paying for upgrades have priority access to 

the capability created by those upgrades, up to the point of the amount of transmission 

service requested. To do otherwise would create disincentives for transmission 

customers later in the queue to pay for upgrades because upgrades must necessarily be 

sized to accommodate all earlier-queued customers. We note, however, that any capacity 

created in excess of the service request should be allocated to those planning redispatch 

and conditional firm customers earlier in the queue, based on their order in the queue. 

585. We also agree with MidAmerican that a transmission provider’s waiver of a 

reassessment for conditional firm or planning redispatch service does not constitute a 

waiver of all reassessments for the duration of the service, unless explicitly agreed to by 

the transmission provider. We reiterate, however, that only one reassessment may be 

performed in each two-year period of service. We also affirm that any waiver must be 

granted for similarly situated service, which would include conditional firm or planning 

redispatch service that is limited because of the same constraints or general system 
Docket No. RM05-17-001, et al. - 309 -

limitations. Such a waiver would be an act of discretion that must be posted on OASIS. 

Waiver of the reassessment presents an opportunity for discrimination among classes of 

customers on the part of the transmission provider and posting will provide eligible 

customers with an indicator of how often conditions or redispatch requirements have 

been reassessed. Transmission providers are directed to develop uniform OASIS posting 

standards, in coordination with NAESB, for transmission providers to post information 

regarding waivers of the biennial reassessment for planning redispatch and conditional 

firm service. 

586. We reiterate in response to E.ON U.S. that both the transmission provider and 

reliability coordinator play a role in ensuring that reliability is maintained when a 

customer uses third-party provided planning redispatch.232 Customers are allowed to use 

their own or third-party resources to secure planning redispatch services in lieu of or in 

addition to service from the transmission provider, provided that the arrangements are 

sufficiently detailed and coordinated with the transmission provider to ensure that 

reliability is maintained. This would entail review of redispatch plans submitted by 

customers, coordination between the transmission provider and reliability coordinator, 

and signaling third party generators when the redispatch is needed. The Commission 

made clear in Order No. 890 that it would be the customers’ ultimate responsibility to 

ensure that any technical arrangements required by the reliability coordinator are in place 

in order to maintain reliability. 

 232 See id. at P 1004-07. 
Docket No. RM05-17-001, et al. - 310 -

587. With regard to the conditional firm option, we continue to require that 

transmission providers study and offer service based on both system conditions and 

annual curtailment hours. The Commission introduced the concept of conditional 

curtailment based on system conditions in its request for supplemental comments issued 

on November 15, 2006. MidAmerican and other industry participants were therefore 

provided adequate notice and opportunity to comment on the potential for the 

Commission to expand the scope of the required offerings for conditional firm service. 

Upon review of these comments, the Commission allowed transmission providers to 

determine system conditions and conditional curtailment hours through different means, 

implicitly recognizing that system conditions are not exactly interchangeable with 

conditional curtailment hours.233 Modeling of conditional curtailment hours entails 

difficulties beyond those encountered in modeling ATC. Transmission providers have 

therefore been granted flexibility in making these determinations and are allowed to use 

an additional risk factor in calculating conditional hours.234 In light of the flexibility 

provided to transmission providers, we reject as unsupported petitioners’ requests to 

eliminate or limit the requirement to offer conditional firm service based on the number 

of hours in which service may be conditional.235 

 233 See id. at P 1065-67. 

234 See id. at P 1067. 

235 We decline requests to extend the date for implementing conditional firm 

service, which has already passed. 
Docket No. RM05-17-001, et al. - 311 -

588. In Order No 890, the Commission allowed transmission providers to add a risk 

factor to their calculation of annual curtailment hours to account for forecasting risks. 

We decline to clarify the level of this risk factor as E.ON U.S. requests. Transmission 

providers need flexibility in modeling these conditions and we will not specify a level of 

appropriate risk factor to apply. We note however that E.ON U.S. lists events that should 

not be evaluated in such analysis. Car accidents, hurricanes, ice storms or other 

unexpected events that require curtailment of firm transmission customers taking service 

over a certain path should not impact the number of non-firm curtailments of conditional 

firm service. 

589. We disagree with MidAmerican’s characterization of curtailment based on system 

conditions as requiring automatic or immediate operator response. Transmission 

providers, especially those with systems susceptible to rapid voltage collapse and 

cascading outages, should manage these situations as they would manage any other 

emergency. The ability to conditionally curtail conditional firm service is not meant to 

address system emergencies, but rather address system conditions such as congestion on 

a line or flowgate, system load levels or the outage of a specific line or generator. We 

affirm the decision in Order No. 890 to require transmission providers to offer eligible 

customers seeking conditional firm service a choice between conditional curtailment 

based on specified system conditions or annual hours. 

590. We clarify in response to Constellation and EPSA that, when a transmission 

provider is evaluating its continued ability to provide conditional firm service during a 

biennial reassessment, the transmission provider is not limited to the specific conditions 
Docket No. RM05-17-001, et al. - 312 -

previously agreed to by the transmission customer in the initial service agreement or a 

prior reassessment. The purpose of the biennial reassessment is to allow the transmission 

provider to adjust the conditions or number of hours during which conditional firm 

service will be conditional in order to ensure that continued provision of the service does 

not impair reliability. Thus, the Commission does not impose upon the transmission 

provider the obligation to plan its system to keep firm the part of the conditional firm 

service that is firm when service was initiated. Although this may increase (or decrease) 

the number of hours in which service is conditional, the transmission provider may not 

entirely terminate service to the conditional firm customer. 

591. We affirm our decision to assign conditional firm service the same curtailment 

priority as secondary network service for periods when the service is conditional. EEI’s 

argument that customers use secondary network service to meet the reliability needs of 

their loads is inapposite. Secondary network service is a non-firm service for which 

requests are made in the same time-frame as other non-firm service.236 While the 

Commission recognized that network customers may use secondary network service on 

an “as available” basis to meet peak native load, and in this way meet the reliability needs 

of loads, this is not the purpose of secondary network service. Network customers that 

rely upon secondary network service to meet their peak native load are already lessening 

the reliability of their service by taking non-firm service. The fact that conditional firm 

 236 See id. at P 1606. 
Docket No. RM05-17-001, et al. - 313 -

service will compete with secondary network service when curtailments are ordered is 

irrelevant. 

592. We agree with petitioners that the NAESB rules regarding tagging do not allow a 

transmission provider to change the tag of a transmission customer. That is why, in 

Order No. 890, the Commission directed transmission providers to coordinate with other 

transmission providers in their regions to develop their own business practices to 

implement the tagging and tracking of conditional firm service.237 Upon consideration of 

petitioners’ concerns, we grant rehearing to require transmission providers, in 

coordination with NERC and NAESB, to develop within 180 days of publication of this 

order in the Federal Register a consistent set of tracking capabilities and business 

practices for tagging for implementation of conditional firm service. We agree with 

petitioners that a consistent set of practices followed by the industry will reduce 

transmission provider discretion and bring uniformity in implementing conditional firm 

service. In the interim, the existing business practices of each transmission provider for 

tracking and tagging conditional firm service shall remain in effect. 

593. We decline to generically waive potential penalties for violations of NERC 

reliability standards due to implementation of conditional firm service, as Southern 

suggests. Southern has not provided enough information to allow us to determine 

whether its implementation of conditional firm service will actually cause violations of 

 237 See id. at P 1077. We clarify that transmission providers may determine the 

season, month and hour for changing the priority of tags for customers taking the annual 

hourly conditional firm option. 
Docket No. RM05-17-001, et al. - 314 -

NERC planning criteria. Transmission providers are able to incorporate the specifics of a 

conditional firm service agreement in their base models to differing degrees, depending 

on the flexibility of different models and the assumptions used in modeling the service. 

Therefore, incorporation of conditional firm service into the base case of models need not 

cause overloads under N-1 conditions. Under the Commission’s regulations, if Southern 

believes a conflict exists between its implementation of the conditional firm option and 

any of NERC’s reliability standards, it must bring that conflict to the attention of the 

Commission, the Electric Reliability Organization and the relevant Regional Entity for 

resolution. Pending resolution of the matter, a transmission provider must continue to 

comply with Order No. 890 and provide conditional firm service. 

594. Finally, we reject as unnecessary TDU Systems’ request to require separate annual 

reporting of conditional firm service revenues. We also decline to generically require all 

transmission providers to address potential updates to transmission rates as a result of 

providing conditional firm service. TDU Systems has not justified treating these 

revenues differently than other long-term firm point-to-point revenues. 

 (2) Pricing of Planning Redispatch

595. The Commission determined that customers taking long-term point-to-point 

service with planning redispatch will have the option of paying either (i) the higher of (a) 

actual incremental costs of redispatch or (b) the applicable embedded cost transmission 

rate on file with the Commission or (ii) a fixed rate for redispatch to be negotiated by the 

transmission provider and customer and subject to a cap representing the total fixed and 

variable costs of the resources expected to provide the service. If the customer selects the 
Docket No. RM05-17-001, et al. - 315 -

higher of incremental cost or the embedded-cost rate, the transmission provider must 

calculate the incremental costs of redispatch monthly and charge the higher of redispatch 

or the embedded cost rate each month. 

596. For purposes of calculating planning redispatch charges, incremental costs must 

include fuel or purchase power costs caused by ramping up generator(s) at the point of 

delivery and ramping down generator(s) at the point of receipt. Where applicable, 

transmission providers also may specify other incremental costs for inclusion in the 

monthly actual incremental costs, including opportunity costs and purchased power costs, 

provided that identification and derivation of these costs is included in the service 

agreement. All information necessary to calculate and verify opportunity costs must be 

made available at the request of the transmission customer.238 

Requests for Rehearing and Clarification

597. Several petitioners argue that customers choosing planning redispatch should pay 

the cost of transmission service and the cost of redispatching generation.239 These 

petitioners generally maintain that the redispatch of generators merely reallocates use of 

existing transmission capability without creating any new thermal transmission capacity. 

 238 Although a transmission provider is not required to contract with a third party 

to provide planning redispatch, if it does so then the customer would be obligated to pay 

the purchase power costs, including any reservation charge for the power. Any flowthrough of purchase power costs must be negotiated between customers and transmission 

providers in a stand-alone agreement if the transmission provider agrees to make 

purchases on the customer’s behalf. 

239 E.g., Ameren, EEI, Progress, Southern, Washington IOUs, and Xcel. 
Docket No. RM05-17-001, et al. - 316 -

EEI and Progress contend that planning redispatch takes away firm transmission capacity 

from network customers and the transmission provider’s native load and gives that 

capacity to a new point-to-point customer, without any corresponding increase in TTC. 

Southern notes that customers agreeing to third-party provided planning redispatch will 

pay both the embedded transmission rate to the transmission provider and the redispatch 

rate charged by the third-party generator. EEI and Southern contend that the pricing of 

planning redispatch should be aligned with the price of reliability redispatch and the 

pricing for third-party provided redispatch, arguing that different cost recovery for 

similarly situated generators is unduly preferential. 

598. EEI also argues that the Commission’s prohibition against recovery of both the 

incremental cost of transmission upgrades and the embedded cost of transmission service 

from the same customer has a different impact on the transmission provider’s ability to 

recover its cost of service than does the prohibition against the recovery of the costs of 

planning redispatch and the costs of the transmission system. When a transmission 

provider constructs additional transmission capacity to serve a new customer, EEI states 

that the transmission provider recovers the entire cost of its transmission system and its 

new facilities and that the only question is how those costs should be allocated between 

new and existing customers. EEI contends that the pricing for planning redispatch leaves 

the transmission provider unable to recover additional costs associated with the service. 

599. Southern argues that customers will receive two distinct services and should be 

charged for both according to cost causation principles. Southern asserts that the 

Commission’s pricing policy for planning redispatch service results in an uncompensated 
Docket No. RM05-17-001, et al. - 317 -

taking of the utility’s property by providing no compensation for either the transmission 

or the generator-supplied redispatch service. Southern concludes that the rate for 

planning redispatch cannot be just and reasonable because the transmission provider will 

provide part of the service for free. E.ON. U.S. similarly argues that LSEs should have 

the opportunity to recover actual fuel costs since those costs are directly attributable to 

the service provided to the redispatch customer. Ameren asks the Commission to clarify 

that all costs, including lost opportunity costs will be recovered in order to avoid 

penalizing the generator and harming native load customers. 

600. EEI argues that the Commission’s rationale for prohibiting the recovery of both 

lost opportunity costs and the cost of transmission service in a pre-open access 

environment is inapplicable to the situation that transmission providers face when they 

must redispatch generating resources to create transmission capacity that would otherwise 

be unavailable.240 According to EEI, the situation in Penelec, in which the utility was 

seeking compensation for the potential loss of future imports of non-firm energy, is 

inapposite to the planning redispatch requirement, in which the customer’s request for 

firm service has priority over the transmission provider’s non-firm use of the system. 

601. If the Commission does not allow recovery of the costs of both transmission 

service and the cost of redispatching generation, EEI and Southern ask the Commission 

to clarify rate treatment for the planning redispatch service. They argue that the long-

 240 Citing Pennsylvania Electric Company, 58 FERC ¶ 61,278 at 62,873, reh’g 

denied, 60 FERC ¶ 61,034 (1992), aff’d sub nom. Pennsylvania Electric Co. v. FERC, 

11 F.3d 207 (D.C. Cir. 1993) (Penelec). 
Docket No. RM05-17-001, et al. - 318 -

term point-to-point reservation that employs planning redispatch should not be included 

in the divisor of a transmission provider’s rate calculation. Instead, Southern argues that 

generation-related payments associated with the redispatch should be treated as a revenue 

credit to off-set native load customers’ fuel adjustment clause and transmission revenues 

from the planning redispatch service should be included in the numerator as a revenue 

credit. EEI contends that transmission providers should be permitted to make a rate 

design change through amendments to their formula rates or in a general or single rate 

case filing. 

Commission Determination

602. The Commission affirms the decision in Order No. 890 not to adopt “and” pricing 

for planning redispatch service. In Order No. 890, the Commission explained that 

planning redispatch differs from reliability redispatch in that planning redispatch service 

creates additional transmission capacity241 and reliability redispatch allows customers to 

avoid real-time curtailments.242 It is appropriate for customers to pay the embedded cost 

of transmission and the cost of third-party redispatch because third parties cannot recover 

 241 See Order No. 890 at P 1029 (citing Order No. 888-A at 30,267). In Order No. 

888-A, the Commission began its discussion of the redispatch obligation and redispatch 

pricing by explaining that “the obligation to create additional transmission capacity to 

accommodate a request for firm transmission service should properly lie with the 

transmission provider, not a network customer.” See Order No. 888-A at 30,267. 

Because a network customer cannot add new transmission upgrades on its own to the 

transmission provider’s system, the Commission was necessarily referring in this 

statement to the planning redispatch obligation. 

242 See Order No. 890 at P 1028. 
Docket No. RM05-17-001, et al. - 319 -

transmission revenues for the additional transmission capability created by their 

redispatch. Thus, different cost recovery for third party, network and transmission 

provider resources providing redispatch is not unduly preferential. 

603. While we agree that planning redispatch does not create new thermal capacity 

equivalent to grid expansion, we disagree with EEI and Southern that planning redispatch 

does not create additional transmission capability and associated revenues for the 

transmission provider. When a transmission provider plans to redispatch its generation 

resources in order to provide previously unavailable firm point-to-point service, it does 

not and should not take firm service away from network and native load customers. The 

transmission provider continues to provide firm service to network and native load 

customers and receives its revenue requirement to serve those customers. The 

transmission provider also adds another long-term firm point-to-point service agreement 

and receives its embedded cost transmission rate for that service, which it would not have 

received but for providing the planned redispatch of its resources. 

604. The pricing of planning redispatch service does not violate cost causation 

principles or amount to an uncompensated taking from utilities. Transmission providers 

will receive on a monthly basis the higher of the cost of redispatching their generators or 

the revenues for transmission service that they would not have received but for the 

redispatch. Transmission providers do not provide the redispatch of their generation for 

free, as Southern contends, nor do they lose the opportunity to recover actual fuel costs, 

as E.ON U.S. suggests. If the monthly embedded-cost transmission rate is lower than the 
Docket No. RM05-17-001, et al. - 320 -

monthly costs of redispatching resources, including actual fuel costs, the higher monthly 

redispatch costs may be recovered. 

605. We will not allow “and” pricing of planning redispatch service, which would 

result in overcompensation of transmission providers and violate the Commission’s longstanding opportunity costs pricing policy announced in Penelec. In Order No. 888, the 

Commission affirmed the rationale in Penelec for allowing utilities to charge opportunity 

costs in an open access environment.243 In Order No. 888-A, the Commission 

specifically concluded that opportunity cost pricing is appropriate for costs that arise 

from a transmission provider having to reduce its off-system sales to avoid a transmission 

constraint and reiterated that off-system sales can only be made pursuant to the point-topoint provisions of the pro forma OATT.244 The Commission also affirmed that “and” 

pricing is not appropriate for planning redispatch service.245 EEI’s assertion that Penelec

is not applicable in a post-open access world is a collateral attack on Order Nos. 888 and 

888-A. 

606. Order No. 888 provided that revenues from direct assignment of redispatch costs 

must be credited to the costs of fuel and purchased power expense included in the 

transmission provider’s wholesale fuel adjustment clause.246 We therefore clarify that, in 

 243 See Order No. 888 at 31,739. 

244 See Order No. 888-A at 30,265, n.261. 

245 Id.

246 See Order No. 888 at 31,740. 
Docket No. RM05-17-001, et al. - 321 -

months in which generation-related payments are collected for planning redispatch, these 

payments should be treated as a revenue credits to off-set native load customers’ fuel 

adjustment clause. In months in which the embedded cost rate of transmission is 

collected for planning redispatch, these revenues should be included in the numerator of 

the rate calculation as a revenue credit. For most planning redispatch service, we believe 

that there will likely be at least one month a year when the actual incremental cost of 

redispatch is higher than the embedded cost rate. For this reason we believe it is 

appropriate for transmission providers to treat transmission revenues from planning 

redispatch service consistent with the rate treatment for revenues from short-term 

transmission reservations. To the extent necessary, a transmission provider may propose 

in an FPA section 205 filing any rate design change that may be necessary through an 

amendment to its formula rate or in a general or single rate case filing. 

(3) Rollover Rights

607. The Commission found in Order No. 890 that rollover rights are appropriate for 

point-to-point service that is provided using planning redispatch or conditional firm 

options and that would otherwise be eligible for rollover rights. The transmission 

provider, however, will continue to have a right to review the conditions or redispatch 

requirements every two years. 

608. The Commission determined that a conditional firm customer opting to roll over 

will retain a priority claim to the portion of its service that is firm. The Commission 

qualified this statement by providing an example: if a five-year conditional firm service 

initially has a 100-hour annual cap on curtailments, but the cap is later reassessed at 150 
Docket No. RM05-17-001, et al. - 322 -

hours, the rollover right would continue to give the customer first call on all but the 150 

hours as against all other subsequent requests for firm service. 

Requests for Rehearing and Clarification

609. TDU Systems and Ameren argue that the Commission erred in allowing rollover 

rights for conditional firm service that is subject to biennial reassessment. TDU Systems 

and Ameren argue that allowing rollover for this service is inconsistent with other 

requirements of Order No. 890 that limit conditional firm service to the shorter term 

service if customers do not agree to pay for upgrades. TDU Systems contend that 

allowing rollover rights for customers taking conditional firm service creates a continued 

opportunity for transmission customers to free ride on transmission capacity built and 

paid for by others. Ameren maintains allowing rollover rights for conditional firm 

agreements will increase uncertainty in modeling and will decrease the incentive to 

upgrade the transmission system. 

Commission Determination

610. The Commission affirms the decision in Order No. 890 to provide rollover rights 

to conditional firm point-to-point service that otherwise qualifies for rollover rights. We 

disagree that granting rollover rights to conditional firm customers is inconsistent with 

statements in Order No. 890 that customers not willing to pay for upgrades should have 

their service limited. Customers taking conditional firm service subject to reassessment 

take the risk that the firmness of their service will deteriorate with every biennial 

reassessment. These customers are not free riding on the transmission grid, but rather are 

taking less than firm service and making a contribution to the embedded costs of the grid 
Docket No. RM05-17-001, et al. - 323 -

by paying the long-term firm transmission rate. Allowing rollover will not increase 

uncertainty in modeling the service, as Ameren contends, because transmission providers 

will still be able to perform biennial reassessments every two years for those conditional 

firm customers not willing to pay for upgrades. 

611. We also disagree that granting rollover rights to conditional firm customers 

decreases incentives to expand the grid. Even without rollover rights, conditional firm 

customers wishing to continue their service could simply submit additional requests for 

service, in response to which the transmission provider would identify the limiting 

conditions for continued service. Granting rollover rights to longer-term conditional firm 

customers allows these customers to keep their place in line ahead of others seeking 

conditional firm service in recognition of the longer-term commitment they made to the 

transmission provider. Ameren’s concern, then, is with the underlying requirement to 

offer conditional firm service, which we affirm above. 

(4) Use of the Conditional Firm Option in Designating 

Network Resources

612. In Order No. 890, the Commission concluded that conditional firm point-to-point 

service is sufficiently firm to support the designation of network resources imported from 

other control areas. The Commission concluded that the conditional firm option only 

affects the transmission of the resource to the network, not the interruptibility of the 

generating resource itself, and the transmission may not be interrupted for reasons other 

than reliability. 
Docket No. RM05-17-001, et al. - 324 -

Requests for Rehearing and Clarification

613. Several petitioners object to allowing conditional firm service to be used to 

support an off-system designated network resource.247 EEI and Progress argue that 

allowing designation of such resources would adversely impact system reliability. EEI 

asserts that some customers may take conditional firm service that is curtailable in all 

summer months, not just 10 to 20 hours a year. EEI contends that conditional firm 

service presents the possibility that the supply of energy from a generator may be 

interrupted for a substantial period of time, well in excess of the time for an interruption 

due to a forced outage or maintenance outage. EEI asserts that this less reliable service to 

serve load will not only impact the conditional firm customer’s supply of energy, but 

could affect other network customers and native load customers. 

614. Duke requests clarification that off-system conditional firm-supported resources 

may qualify as designated network resources only if the network customer clearly 

specifies in its Network Integration Transmission Service Agreement specific backup 

arrangements, such as adequate reserves. Duke also asks the Commission to clarify that a 

transmission provider need not undertake provider-of-last-resort obligations to any 

network customer that elects to designate a network resource supported by conditional 

firm service. 

615. PJM asks the Commission to clarify that Order No. 890 does not require it to 

accept conditional firm service as sufficient to qualify external generating resources as 

 247 E.g., Duke, EEI, Progress, and TDU Systems. 
Docket No. RM05-17-001, et al. - 325 -

capacity resources for purposes of PJM’s Reliability Pricing Model (RPM). In order to 

qualify as a capacity resource, PJM asserts that an external unit must have a firm path to 

load that is available year-round, particularly during high-level periods when adjacent 

control areas both are experiencing system stresses. 

Commission Determination

616. The Commission affirms the decision in Order No. 890 to allow the designation of 

off-system resources supported by conditional firm point-to-point service.248 It is 

appropriate to allow conditional firm service to support the designation of network 

resources because the conditional firm option only affects the transmission of the 

resource to the network, not the interruptibility of the generating resource itself. 

Conditional firm service satisfies the requirement that the delivery of the resource to the 

network to be non-interruptible because conditional firm transmission service is 

curtailable only for specific reliability reasons, not for economic reasons. 

617. We acknowledge that conditional firm service may have conditions that apply for 

most of the peak periods of a month or season. This does not mean that such service will 

necessarily impact the reliability of the transmission provider’s system. The Commission 

declines Duke’s request to require a network customer with a designated off-system 

resource supported by conditional firm service to obtain reserves or backup resources to 

cover the periods when the resource supported with conditional firm point-to-point 

transmission service might not be delivered. It is not the responsibility of the 

 248 See Order No. 890 at P 1091. 
Docket No. RM05-17-001, et al. - 326 -

transmission provider to ensure that the network customer has sufficient resources to 

meet its load. 

618. Whether or not off-system resources supported by conditional firm service may 

serve as a capacity resource under PJM’s RPM is governed by the relevant RPM rules 

adopted by PJM, which were not addressed in Order No. 890. 

c. Proposals for Transparent Redispatch

619. In Order No. 890, the Commission rejected requests to expand the transmission 

provider’s real-time redispatch obligations to incorporate third-party bids for redispatch 

or otherwise require reliability redispatch to be offered to point-to-point customers. The 

Commission concluded that the provision of reliability redispatch only to network 

customers did not constitute undue discrimination because, unlike point-to-point 

customers, network customers are required to make their generation resources available 

to the transmission provider to provide reliability redispatch to maintain the reliability of 

both native load and network service. The Commission also determined that mandatory 

inclusion of third party offers to redispatch is not necessary to remedy undue 

discrimination because, unlike the transmission provider, third party generators are under 

no obligation to make their resources available to provide redispatch. 

620. The Commission did, however, require that transmission providers post certain 

redispatch cost information associated with the existing redispatch services that must be 

provided under the pro forma OATT. The Commission concluded that providing 

customers with additional transparency and greater information regarding the cost of 

congestion will facilitate their consideration of planning redispatch options, which in turn 
Docket No. RM05-17-001, et al. - 327 -

will provide for more efficient use of the grid. To that end, the Commission directed 

each transmission provider to post on OASIS its monthly average cost of redispatch for 

each internal congested transmission facility or interface over which it provides planning 

redispatch or reliability redispatch under the pro forma OATT. In addition, to 

demonstrate the range of redispatch costs each month, the Commission directed 

transmission providers to post a high and low redispatch cost for the month for each of 

these same transmission constraints. 

621. Transmission providers must post internal constraint or interface data for the 

month if any planning redispatch or reliability redispatch is provided during the month, 

regardless of whether the transmission customer is required to reimburse the transmission 

provider for those exact costs. Thus, if the transmission customer pays for planning 

redispatch pursuant to a negotiated fixed rate, the transmission provider is required to 

post and calculate the monthly average redispatch costs and the high and low costs in the 

month even though the transmission provider will bill the customer the fixed rate. The 

same posting requirement applies if the customer is paying a monthly “higher of” rate. 

The Commission concluded that the relevant reliability redispatch costs for posting 

purposes are those costs the transmission provider invoices network customers based on a 

load ratio share pursuant to section 33.3 of the pro forma OATT.249 The transmission 

 249 Order No. 890 provided that the transmission provider need not perform new 

calculations of out-of-merit redispatch costs; rather the reliability redispatch invoices 

should form the basis of information from which the transmission provider determines 

monthly average reliability redispatch costs. 
Docket No. RM05-17-001, et al. - 328 -

provider must post this data on OASIS as soon as practical after the end of each month, 

but no later than when it sends invoices to transmission customers for redispatch-related 

services. The Commission directed transmission providers to work in conjunction with 

NAESB to develop this new OASIS functionality and any necessary business practice 

standards. 

Requests for Rehearing and Clarification

622. Ameren argues that the redispatch cost posting requirement is unreasonable 

because it creates a substantial new burden for transmission providers without creating 

offsetting benefits for transmission customers. Ameren maintains that the Commission 

failed to assess the benefits and the burdens of the redispatch costs posting requirement. 

Ameren also maintains that this information will not provide any value to the 

transmission customer in anticipating redispatch costs since certain factors embedded in 

the calculation of these costs, including fuel, will vary greatly over time. Ameren 

concludes that existing requirements under the pro forma OATT are all that is necessary 

to provide transparency for the service. 

623. Progress Energy requests clarification that reliability redispatch costs need only be 

posted if the transmission provider invoices network customers for those costs. Progress 

Energy states that Order No. 890 contains language that could be read to require the 

posting of reliability redispatch costs even if network customers are not invoiced for 

those costs, notwithstanding the Commission’s statement that the relevant reliability 

redispatch costs for posting purposes are those costs the transmission provider invoices 
Docket No. RM05-17-001, et al. - 329 -

network customers.250 Progress Energy concludes that it would be unduly burdensome 

and serve no regulatory purpose to require transmission providers to post reliability 

redispatch costs when they are not invoicing their network customers for these costs. 

624. Entergy requests clarification that, when redispatch charges are calculated and 

charged on a system average basis, only the average costs for the system for the month 

need be posted. Entergy states that its new weekly procurement process will provide 

customers a greater opportunity to obtain transmission service by paying redispatch costs, 

as determined through the optimization models in the weekly procurement process. 

These optimization models will not calculate redispatch costs for each specific 

constrained facility on Entergy’s system. Entergy states it would incur additional 

burdens if required to separately calculate these costs to meet the Order No. 890 

requirement to post redispatch costs by each constrained facility. 

Commission Determination

625. The Commission affirms the decision in Order No. 890 to require transmission 

providers to post on OASIS monthly average redispatch costs for each internal congested 

transmission facility and interface over which planning redispatch or reliability dispatch 

are provided under the pro forma OATT. We disagree with Ameren that this creates a 

substantial new reporting burden for transmission providers. The information to be 

posted is readily available to transmission providers from the invoices used to charge 

network customers, in the case of reliability redispatch costs, or calculations that the 

 250 Citing Order No. 890 at P 1162, n.707. 
Docket No. RM05-17-001, et al. - 330 -

transmission provider performs to bill for planning redispatch services. The only added 

burden involves posting those previously calculated costs and calculating averages in 

order to mask commercially sensitive information. This additional averaging step was 

instituted to address concerns raised by Ameren and others about release of proprietary or 

confidential market information.251 Although we do not believe this averaging step to be 

unduly burdensome, Ameren or any other transmission provider may propose a variation 

from the pro forma OATT to allow for posting of actual billing data if the transmission 

provider believes it is too burdensome to average this data prior to posting. 

626. Any minimal burden imposed on transmission providers by the redispatch cost 

posting requirement is offset by the benefits of providing customers with fairly current 

information regarding which facilities are congested each month and the average costs of 

redispatch over those facilities. 252 This information has previously been provided only to 

customers receiving specific redispatch services. While redispatch costs incurred by 

customers in the present do not always correlate with future redispatch costs, a fact 

recognized by the Commission in Order No. 890,253 more information on the currently 

provided redispatch could be invaluable to a potential or current customer evaluating 

different generation and transmission options. A reporting requirement that allows 

customers to identify constraints and the monthly average costs of relieving those 

 251 See id. at P 1150. 

252 See id. at P 1163. 

253 See id. at P 1159. 
Docket No. RM05-17-001, et al. - 331 -

constraints provides a benefit to customers that outweighs the small monthly posting 

burden. 

627. To the extent necessary, we clarify in response to Progress Energy that 

transmission providers that do not calculate and charge separate reliability dispatch 

charges to its network customers have no obligation to report monthly redispatch costs 

for those services. The posting obligations adopted in Order No. 890 were designed so 

that transmission providers could post redispatch cost information based on data already 

calculated for another purpose, including customer invoices for reliability dispatch and 

the determination of charges for the monthly “higher of” rate for planning redispatch.254 

If redispatch costs are calculated and charged on a system-wide basis rather than for each 

constraint on the system, the transmission provider has no obligation to perform new 

calculations to estimate the redispatch costs for each constraint on its system. We 

therefore agree with Entergy that, in the described situation, only the average costs for the 

system for the month, including the highest and lowest system average redispatch costs in 

an hour for the month, need be posted. 

d. Other Requested Service Modifications 

628. The Commission rejected requests to adopt other new services or modifications to 

existing services beyond those reforms adopted in Order No. 890. Among other things, 

 254 The posting requirement for the newly instituted negotiated fixed rate pricing 

option for planning redispatch is an exception. If a transmission provider chooses to 

negotiate a fixed rate for planning redispatch, it must determine and report the redispatch 

costs for providing that service even though it might not otherwise need to calculate these 

costs. 
Docket No. RM05-17-001, et al. - 332 -

the Commission declined to require transmission providers to offer a dynamic scheduling 

service for loads and resources that are located in different transmission providers’ areas. 

The Commission stated that transmission providers seeking to provide this or additional 

new services may submit an FPA section 205 filing to propose modifications to their 

OATT, which would be considered on a case-by-case basis. 

Requests for Rehearing and Clarification

629. TAPS requests that the Commission require transmission providers to include 

provisions in their OATTs that would permit a transmission dependent utility with loads 

and resources in multiple control areas to consolidate them into a single control area via 

dynamic scheduling. TAPS states that a control area utility with remote generation 

and/or load has the option to use a pseudo-tie to import generation into its control area. 

TAPS argues that transmission dependent utilities should have comparable options priced 

at the transmission provider’s cost. TAPS contends that leaving transmission dependent 

utilities in the position of having to negotiate with the transmission providers for this 

option will leave them exposed to unjust and unreasonable and unduly discriminatory 

imbalance pricing. TAPS also argues that changes to the OATT to allow for dynamic 

scheduling should not disturb already existing dynamic scheduling agreements that have 

been successfully negotiated by transmission dependent utilities. 

Commission Determination

630. The Commission denies rehearing of the decision in Order No. 890 to not mandate 

a dynamic scheduling service in the pro forma OATT. Dynamic schedules and pseudoties are both services that involve metering, telemetry, computer software, hardware, 
Docket No. RM05-17-001, et al. - 333 -

communications, engineering and administration. Each service is crafted to meet the 

unique needs of each customer, typically requiring the cooperation and services of at least 

two control areas as well as contractor-providers of the components of the services. 

Comparability does not require the transmission provider to undertake these negotiations 

on behalf of its network customers. The unique, customer-specific nature of these 

services are more properly arranged by negotiation between the relevant parties rather 

than standardized in the pro forma OATT. However, to the extent a transmission 

provider currently accepts telemetered generation schedules for its native load, the 

transmission provider must accept such schedules from its network customers on a 

comparable basis. 

631. The Commission is also concerned that the mandatory cost-based provision of 

pseudo-ties could allow transmission customers to cherry-pick among transmission 

providers based on differences in service, including ancillary service costs, and could 

cause insurmountable planning and reliability problems for transmission providers. 

Under a pseudo-tie, the control area receiving the new load or generation signal assumes 

responsibility for ensuring that the load is properly balanced moment-to-moment, for 

planning for the load, and for providing various other ancillary services including energy 

or generator balancing service. We decline to impose unlimited planning, reliability and 

ancillary service requirements on transmission providers by forcing them to accept any 

load or generator that seeks to move to their systems. We are encouraged, however, by 

the increased availability of pseudo-ties and dynamic schedules in the industry. TAPS 
Docket No. RM05-17-001, et al. - 334 -

and others have been able to secure dynamic scheduling agreements on a negotiated 

basis, and we do not intend to disrupt those agreements in this proceeding. 

2. Rollover Rights

632. In Order No. 890, the Commission revised the rollover provision in section 2.2 of 

the pro forma OATT, which grants an ongoing right to firm transmission customers to 

renew or “rollover” their contracts. Under Order No. 888, transmission customers were 

allowed to rollover contracts with a minimum term of one year, provided that they 

provide notification of the rollover no later than 60 days prior to expiration of their 

service agreements. The Commission concluded that this provision was no longer just 

and reasonable, extending the minimum term necessary to qualify for a rollover to five 

years and the notice deadline to one year. Thus, a transmission customer must agree to 

another five-year contract term or match any longer term competing request within one 

year of expiration of its five-year service agreement in order to be eligible for a 

subsequent rollover. The Commission stated that this reform will become effective for 

each transmission provider upon acceptance of the transmission provider’s compliance 

filing containing a coordinated and regional planning process that satisfies the 

requirements of Order No. 890.

633. The Commission declined to eliminate the requirement that an existing 

transmission customer match competing offers as to term and rate in order to roll over its 

service. The Commission also continued to require rollover restrictions to be based only 

on reasonable forecasts of native load growth or preexisting contracts that commence in 
Docket No. RM05-17-001, et al. - 335 -

the future. The Commission affirmed that any restrictions on a customer’s rollover rights 

must be included in the initial transmission service agreement. 

a. Five-Year Minimum Contract Term

Requests for Rehearing and Clarification

634. APPA, NCEMC, TAPS, and TDU Systems state a general concern that, under 

current market conditions, some transmission customers may be unable to obtain power 

supplies of a term and firmness required to support a five-year firm transmission 

agreement. Each of these petitioners note that FPA section 217(b)(4) requires the 

Commission to 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 [their] service obligations . . . 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.” These petitioners argue that the Commission’s 

rollover reforms impede, rather than facilitate, the ability of LSEs to secure firm 

transmission rights on a long-term basis to meet their service obligations. 

635. TDU Systems and NCEMC suggest that implementation of the five-year minimum 

contract requirement for obtaining rollover rights be conditioned on a demonstration that 

the relevant generation markets can support five-year power supply contracts. TDU 

Systems state that the Commission misinterpreted its initial comments on this issue as a 

request to require transmission providers to engage in the business of procuring supplies 

for their transmission customers. TDU Systems explain that they only requested that the 

Commission determine whether market conditions are such that transmission customers 
Docket No. RM05-17-001, et al. - 336 -

themselves may procure five-year generation contracts, such as by using the HerfindahlHirshman Index as a tool for determining the competitiveness of the relevant generation 

markets. 

636. TAPS argues that, where transmission constraints exist, a customer could be 

forced to remain with an incumbent supplier or face the loss of its rights to continued use 

of the grid. NCEMC expresses similar concerns, arguing that on constrained systems the 

rollover reforms significantly increase the potential for market power abuse. NCEMC 

contends that an incumbent generator can limit an LSE’s access to rollover rights by 

simply refusing to offer five-year power supply contracts. 

637. TAPS further argues that these concerns are not adequately addressed by other 

reforms adopted in Order No. 890, as suggested by the Commission. TAPS contends that 

many of these reforms, such as those involving conditional firm and planning redispatch, 

redirects, and capacity reassignment, apply only to point-to-point service, not network 

service. TAPS argues that reforms increasing the accuracy of ATC calculations will not 

help if the calculation results in zero ATC and that coordinated transmission planning 

will only help if it results in actual construction of transmission expansions. APPA 

similarly argues that any benefits from increased coordination in transmission planning 

will take some time to develop.

638. APPA and TAPS contend that the Commission should condition the requirement 

of a five-year minimum contract term to obtain a rollover right on allowing customers 

that enter into such contracts the flexibility to modify receipt points and resource 

designations as their power supply needs change. TAPS argues that the Commission 
Docket No. RM05-17-001, et al. - 337 -

should grant certain clarifications regarding network customers’ rollover rights, in 

recognition of the fact that such customers pay for the transmission provider’s whole 

system. First, TAPS asks the Commission to make clear that the customer is not 

restricted to its existing supplier by requiring transmission providers to flexibly 

accommodate changed resources so that network customers have the benefit of continued 

use of the transmission system planned on their behalf and paid for on a load ratio share 

basis. Second, TAPS asks the Commission, at a minimum, to affirm the existing 

requirement that a new resource should not be rejected as a rollover simply because it is 

not identical to the prior resource, i.e., that a rollover must be allowed unless there is a 

“substantial change” in the direction of flows. Third, TAPS requests that the 

Commission require the transmission provider, at least until compliance with planningrelated reforms, to accept a network customer’s timely designated network resource, even 

if necessary through redispatch (with costs shared on a load ratio basis), unless the 

transmission provider can show that the customer’s supply choice was not reasonably 

foreseeable. Alternatively, TAPS argues that the Commission should require cost-based 

sales to the trapped embedded transmission dependent utility. 

639. TDU Systems state that rollover rights should be allowed unless there is a 

substantial change in power flows and argues further that transmission providers should 

be required to permit rollover of a network customer’s resource if the transmission 

provider would accord itself rollover of the resource if it served the transmission 

provider’s load. TDU Systems argue that transmission providers commonly treat their 

entire transmission systems as single sinks and apply redispatch in order to accommodate 
Docket No. RM05-17-001, et al. - 338 -

rollover of their own network resources, while at the same time, they evaluate other 

users’ rollovers of network resources non-comparably, strictly on the basis of flows to 

discrete load centers, without the benefit of redispatch. TDU Systems contend that this 

practice discriminates against network customers. AMP-Ohio asks the Commission to 

clarify that a network customer is permitted to roll over a portion of a long-term 

reservation. 

640. Morgan Stanley argues that the Commission failed to address its argument that 

limiting rollover rights to customers with firm transmission contracts of five years in 

length or more establishes significant barriers to entry. Morgan Stanley contends the 

credit and collateral requirements to enter into a five-year commitment are much higher 

than those necessary to enter into a one-year deal and that this higher credit requirement 

could limit the variety and flexibility of the resources available to serve load. Morgan 

Stanley also argues that extending the minimum term to five years will result in an 

increase in transmission costs without any corresponding benefits to parties trying to 

serve load. Morgan Stanley asserts that transmission customers choosing to serve load 

will have to purchase more capacity than needed, which will make less capacity available 

for others and will increase costs to the loads served. 

641. Morgan Stanley also argues that the change in rollover right policy discriminates 

against merchant generators, like Morgan Stanley, that do not have load linked to 

generation. Morgan Stanley contends that forcing a merchant generator to purchase 

longer-term transmission will increase its costs to build and encourage local utilities to 

build their own generation rather than seek competitive alternatives. Morgan Stanley 
Docket No. RM05-17-001, et al. - 339 -

repeats arguments that the lack of firm, long-term transmission reservations in the 

California and New England organized markets belies the Commission’s findings that 

contract certainty is needed in order for transmission providers to appropriately plan and 

construct their systems. 

642. Ameren similarly argues that the Commission failed to consider the effect on the 

markets of limiting rollover rights to contracts with a minimum term of five years, 

particularly with regard to markets in which utilities meet their energy needs through 

annual auctions or requests for proposals. Ameren contends that a one-year minimum 

term should be all that is necessary for a customer to roll over its service, arguing that 

current market conditions and the volatility in fuel prices make it undesirable for power 

sellers and power purchasers alike to enter into longer contracts. Ameren also questions 

the Commission’s argument that rollover reforms are needed to improve transmission 

planning, arguing that the lack of transmission infrastructure demonstrates that the prior 

rollover policy did not in fact lead to overbuilding. Ameren asserts that there will be 

fewer contracts with rollover rights under the new policy and, as a result, planning and 

reliability will be harmed because transmission providers will only have to plan for this 

more limited group of contracts. At the same time, Ameren argues that the viability of 

the short-term market will be impaired because the ability of transmission customers to 

continue their service will be placed in doubt. Ameren contends that this scenario will be 

exacerbated in organized markets where many sales and purchases occur in short-term or 

spot markets. If the Commission declines to grant rehearing regarding the five-year 

minimum term requirement, Ameren asks the Commission to clarify that it is eliminating 
Docket No. RM05-17-001, et al. - 340 -

the requirement for transmission providers to plan their systems to accommodate 

transmission customers with contracts that are shorter than five years. 

643. Williams suggests that the minimum term for the exercise of rollover rights should 

be three years, as it believes this better balances the respective rights and obligations of 

transmission customers and transmission providers. Williams argues that extending the 

minimum rollover term will result in less flexibility for transmission customers to adjust 

to changing market conditions and more harm to competition. Williams provides an 

example of a customer receiving non-firm service due to a redirected transmission service 

request, asserting that the customer would be “saddled” with non-firm service for the 

duration of the minimum term, notwithstanding the fact that prior to the redirect the 

customer contracted for firm service. Although the customer would still receive the 

same, non-firm service under a three-year minimum term, the shorter term enables the 

customer to return to the benefit of its bargain sooner and better reflects the initial intent 

of the parties.

Commission Determination 

644. The Commission affirms the decision in Order No. 890 to limit rollover rights to 

contracts with a minimum term of five years. As the Commission explained in Order No. 

890, the prior rollover policy was no longer just, reasonable, and not unduly 

discriminatory because the rights and obligations of a rollover customer no longer bore a 

rational relationship to the planning and construction obligations imposed on the 

transmission provider by the rollover rights. We continue to believe that a five-year term 

will ensure greater consistency between the rights and obligations of customers and the 
Docket No. RM05-17-001, et al. - 341 -

corresponding planning and construction obligations of transmission providers. While 

we appreciate that this reform will affect the way customers retain transmission service, 

other reforms adopted in Order No. 890 will mitigate the concerns of shorter-term 

customers, in particular the obligation for transmission providers to adopt an open, 

coordinated and transparent process for planning to meet the transmission needs of all 

customers.

645. The Commission takes seriously the concerns and allegations about the presence 

of generation market power and the lack of availability of long-term power contracts, and 

we will continue to address these issues in other contexts, in particular our market-based 

rate program. The purpose of our reform of the rollover policy, however, is to align the 

rights and obligations of the customer with those of the transmission provider, not with 

the availability of supplies within a market or particular commercial practices in a region. 

A point-to-point customer need not have a five-year power contract in order to secure a 

five-year transmission service contract. Similarly, it is the length of a network 

customer’s network service agreement, not the length of the power contract supporting a 

network resource designation, that determines whether the customer is eligible for 

rollover.255 Thus, the availability of five-year power contracts is not determinative of the 

ability of transmission customers to obtain rollover rights.

 255 See Wisconsin Pub. Power Inc. SYSTEM v. Wisconsin Pub. Serv. Corp., 84 

FERC ¶ 61,120 at 61,659 (1998) (WPPI). 
Docket No. RM05-17-001, et al. - 342 -

646. We acknowledge that entering into longer-term transmission service agreements 

might increase risk or reduce flexibility for some customers, including merchant 

generators, as they manage their power supplies and transmission contracts. Balanced 

against this potentially negative effect, however, are the many benefits that will flow 

from rollover reform. Under the prior rollover policy, a customer could secure 

transmission for one year and effectively require the transmission provider to plan and 

upgrade its system on the assumption the rollover right would be continually renewed. 

As the Commission noted in Order No. 890, it is inappropriate to require transmission 

providers to use finite resources to finance and construct facilities that may not be 

necessary, particularly in light of the difficulty of siting new transmission.256 The prior 

rollover policy also harmed other transmission customers by allowing rollover customers 

to lock up existing capacity that could have been used by other customers. A minimum 

term of five years, and not a shorter period such as three years as suggested by Williams, 

best balances the benefits and burdens associated with our rollover policy.

647. In response to TAPS, we clarify that we did not intend in Order No. 890 to restrict 

the rollover right to exactly the same points of receipt and delivery as the terminating 

service, as this would competitively disadvantage existing customers seeking new 

sources of generation. As the Commission explained in Order Nos. 888 and 888-A, “if 

the customer chooses a new power supplier and this substantially changes the location or 

direction of the power flows it imposes on the transmission provider’s system, the 

 256 See Order No. 890 at P 1233. 
Docket No. RM05-17-001, et al. - 343 -

customer’s right to continue taking transmission service from its existing transmission 

provider may be affected by transmission constraints associated with the change.”257 

Thus, a transmission provider must allow a rollover, even where a transmission customer 

changes power suppliers, so long as there is no substantial change in the location or 

direction of the power flows imposed on the transmission provider’s system. Moreover, 

we agree with TDU Systems that it would be inappropriate for transmission providers to 

treat a network customer’s request for rollover to accommodate a new designated 

network resource differently than they treat their own new resources for their own loads. 

Transmission providers must permit rollover of a network resource by another user if it 

would accord itself rollover of the resource if it served the transmission provider’s load. 

648. We do not believe, however, that it is appropriate to expand the rights of rollover 

customers as requested by some petitioners. We therefore decline to condition the 

requirement of a five-year minimum contract term on allowing customers signing such 

agreements unlimited flexibility to modify their designated resources and receipt points 

as their power supply needs change within their five-year transmission service 

agreements. As the Commission explained in Order No. 890, such an approach is 

unworkable because it could result in substantial disruptions in transmission service to 

higher queued customers requesting long-term service over these paths.258 The fact that 

network customers pay a load-ratio share of system costs does not justify granting such 

 257 See Order No. 888-A at 30,198, n.52 (citing Order No. 888 at 31,665, n.176). 

258 See Order No. 890 at P 1236. 
Docket No. RM05-17-001, et al. - 344 -

customers a guaranteed ability to change their service to other points without regard to 

other competing requests for service that may be in the queue. Without a limit on 

rollover customers’ flexibility to modify designated resources and receipt points, neither 

the transmission provider nor any other customer in the queue would ever be able to rely 

on any study process for service, as it could be thrown into disarray by a rollover 

customer seeking to change its points. The only way such a system could work would be 

if every transmission provider constructs its system with sufficient redundancy to permit 

any customer to take service from any resource, which would be both impractical and 

uneconomic. 

649. We also disagree that our reforms to rollover policy will harm planning and 

reliability, even if it does result in fewer contracts with rollover rights. As we note 

above, shorter-term transmission customers no longer eligible for rollover rights will 

nonetheless have access to the coordinated, open, and transparent transmission planning 

process required in Order No. 890, which will help ensure that transmission providers 

adequately and comparably plan for the transmission needs of all of their customers 

whether or not they have rollover rights. This is one of the reasons why the Commission 

conditioned the effectiveness of the rollover reforms on its acceptance of a transmission 

provider’s Attachment K planning process in compliance with the transmission planning 

principles adopted in Order No. 890. By extending the minimum term for rollover rights, 

the Commission simply relieved transmission providers of the obligation to undertake 

construction on behalf of shorter-term customers that may not ultimately need the 

facilities.
Docket No. RM05-17-001, et al. - 345 -

650. We reject the suggestion that a five-year minimum is inconsistent with the 

requirements of FPA section 217. Limiting rollover rights to contracts with a minimum 

term of five-years ensures that the rollover right is used by customers with longer-term 

obligations to purchase capacity, benefiting all longer-term customers by limiting the 

ability of shorter-term customers to lock up capacity they do not intend to use and 

facilitating efficient planning and expansion decisions by the transmission provider. 

These benefits are shared by the entire class of customers to which section 217 applies. 

651. In response to AMP-Ohio, we clarify that both network customers and point-topoint customers may roll over a portion of their service, provided that they will only 

obtain a subsequent rollover right if they agree to another five-year term, or match any 

longer term competing request, for that portion of capacity.

b. One-Year Notice Provision

Requests for Rehearing and Clarification

652. Duke asks the Commission to further revise the rollover notification provisions to 

provide for additional time for construction of new facilities in the event project upgrades 

and lead times have been identified. Duke argues that the Commission failed to explain 

in Order No. 890 why it is reasonable to expect on-system LSEs, including the 

transmission provider, to coordinate their resource plans with the lead-time for new 

transmission facilities, but it is not reasonable to expect off-system LSEs that rely upon 

point-to-point service to be subject to the same realities. Because an LSE that is a 

network customer on one system must provide sufficient and adequate notice for its 

transmission provider to accommodate an on-system designated network resource, Duke 
Docket No. RM05-17-001, et al. - 346 -

contends that the one-year notification requirement for rollovers means that the same 

LSE need not provide a neighboring transmission provider the same level of notice to 

accommodate a point-to-point rollover request even if related to the very same designated 

network resource. Duke further argues that the Commission failed to explain why the 

native load protection rationale that prompted adoption of the initial five-year eligibility 

provision should not apply with equal force to the notification provision. 

653. Duke states that, in its experience, most LSEs do not wait until one year before the 

expiration of their contract resources to make decisions as to a replacement resource. In 

the event an LSE does choose to wait until one year before its current supply contract 

ends, Duke argues that the LSE’s decision should not disadvantage native load and 

network customers if, as the Commission recognized, necessary transmission upgrades 

cannot be completed within that one-year period. Duke contends that modification of the 

one-year notice requirement is necessary to ensure greater consistency between the rights 

and obligations of customers and the corresponding planning and construction obligations 

of transmission providers, the stated goal of the Commission’s rollover reforms. If the 

Commission is unwilling to change the one-year notice provision, Duke suggests that the 

Commission provide that a rollover customer’s service will be conditionally firm during 

the period prior to the point in time when needed transmission upgrades can be 

completed. 

654. Southern expresses a similar concern, arguing that a customer should be required 

to provide notice of its intent to exercise its rollover rights at the earlier of one year or the 

lead-time for any construction of upgrades identified by the transmission provider in the 
Docket No. RM05-17-001, et al. - 347 -

service agreement that are necessary in order to reliably exercise the rollover right. 

Southern contends that this requirement would be consistent with the ability of the 

transmission provider to place in the original service agreement limits on the customer’s 

ability to exercise rollover rights and is needed to maintain reliability and protect the 

provision of service to other firm users of the transmission system, including native load. 

Commission Determination

655. We affirm the decision in Order No. 890 to require customers to notify the 

transmission provider of their intent to exercise their rollover rights at least one year 

before expiration of their service agreement. We reject requests to tie the notice period to 

the construction lead-times for any upgrades a transmission provider may believe are 

necessary in order to accommodate any rolled over service along with its other service 

obligations. The Commission recognized in Order No. 890 that the one-year notice 

period is shorter than the typical planning horizon, but declined to extend the notice 

period to a time that coincides with the typical planning horizon or the time it takes to 

construct new facilities.259 The Commission balanced the circumstances facing 

customers in renewing power supply contracts and the interests of transmission providers 

in attempting to plan their system. We continue to believe that the one-year notice 

provision most appropriately balances these competing interests. 

656. We acknowledge that, in certain circumstances, the one-year notice period could 

cause the transmission provider to undertake construction of facilities that are not 

 259 See id. at P 1247. 
Docket No. RM05-17-001, et al. - 348 -

ultimately needed to accommodate other service obligations in light of a rollover 

customer declining to rollover its service. However, moving from a 60-day notice period 

to one year should mitigate the risk of unnecessary investments. While allowing a 

transmission provider to require rollover notification prior to construction of facilities 

(whether or not identified in the original service agreement), or treating the customer’s 

service as conditionally firm while upgrades are completed, would further reduce this risk 

for the transmission provider, it also would further decrease flexibility for the 

transmission customer. As the Commission explained in Order No. 890, no single notice 

period can perfectly balance the needs of customers and transmission providers.260 The 

Commission concluded that a one-year notice provision best balances the respective 

benefits and burdens for customers and transmission providers, and we affirm that 

decision here. 

c. Matching Competing Requests

 Requests for Rehearing and Clarification

657. APPA argues that the Commission’s retention of its matching policy, requiring 

transmission customers to match competing requests for service as to term and rate, is 

inconsistent with FPA section 217(b)(4). In APPA’s view, section 217(b)(4) requires the 

Commission to exercise its FPA authorities to assist LSEs in meeting their service 

obligations by securing firm transmission rights on a long-term basis. APPA contends it 

is contrary to Congressional intent to require LSEs that have made long-term financial 

 260 See id. at P 1246. 
Docket No. RM05-17-001, et al. - 349 -

commitments to the transmission system, by entering into five-year agreements, to bid 

against all other interested market participants in order to roll over their firm transmission 

rights. 

658. APPA also argues that the Commission’s decision to lift the price cap on 

reassignments of firm transmission capacity might exacerbate the situation, as it could 

mean that LSEs will have to bid against well-heeled financial players or marketing 

affiliates of the transmission provider that may be bidding for the same capacity with the 

sole intent of reassigning it at whatever price the market will bear. APPA contends that 

this would require LSEs unable to match the longer term offered (due, for example, to its 

inability to obtain a power supply contract of that length) to have to obtain firm 

transmission capacity in the reassignment market at a much higher rate. APPA argues 

that this, too, is inconsistent with the Commission’s obligation under FPA section 

217(b)(4) to enable LSEs with service obligations to obtain the long-term firm 

transmission rights they must have to meet those needs. 

659. APPA adds that the transmission provider should have been planning for the needs 

of firm transmission customers with contracts that carry rollover rights throughout the 

term of the contract, since the stated purpose of the rollover reform is to ensure that the 

rights and obligations of the customer are better aligned with the planning and 

construction obligations of the transmission provider. APPA argues that capacity should 

therefore be available to meet the needs of firm transmission customers seeking to 

exercise their rollover rights without forcing them to “bid on the margin” for transmission 

capacity every time their contracts come up for renewal. 
Docket No. RM05-17-001, et al. - 350 -

660. TAPS proposes what it characterizes as safeguards to prevent network customers 

exercising rollover rights from being significantly disadvantaged by the obligation to 

match point-to-point reservations. TAPS contends that a point-to-point customer, faced 

with a competing longer-term reservation, can simply extend the term of its point-topoint commitment to match the competing request. If the matching process applies to 

network service designations under a network service agreement (versus the service 

agreement itself), TAPS contends that the network customer would need to extend its 

power supply commitment in order to extend its transmission reservation to match the 

competing request and would not be able to resell any transmission capacity for which it 

could not find supplies. TAPS argues that this fails to recognize and preserve the LSE’s 

continuing rights under FPA section 217(b)(1) to (3) to use their existing firm 

transmission rights, including rollover rights, and that it is inconsistent with section 

217(b)(4) for the Commission to leave transmission-dependent LSEs at risk of denial of 

continued use of transmission to meet their service obligations. 

661. TAPS therefore suggests that the Commission implement matching based on the 

duration of a network customer’s network service agreement rather than its resource 

designation. Alternatively, if the Commission concludes that the network customer must 

extend its resource commitment (rather than just its network agreement duration) to 

match a competing request, TAPS proposes the following modifications to the process so 

that the network customer is on a level playing field with competing point-to-point 

customers in the matching process: restrict reservations qualified to compete against a 

network customer’s reservation to customers with long-term power contracts (even if 
Docket No. RM05-17-001, et al. - 351 -

they seek only point-to-point reservations); and provide a cut-off for competing requests 

that accommodates the network customer’s need to extend power supply arrangements in 

order to match competing requests. TAPS suggests, for example, that the network 

customer should only need to compete with requests submitted at least three months prior 

to when the network customer exercises its rollover right, which would allow the network 

customer to structure its power supply commitments with some degree of advanced 

knowledge of the competing requests. TAPS also suggests that such a rolling cut-off 

(i.e., one tied to the network customer’s rollover notice) be adopted to encourage early 

exercise of rollover rights, thereby benefiting the planning process. 

662. TDU Systems suggest that the Commission cap the matching term required to 

secure rollover rights to five years, arguing that a customer agreeing to pay the maximum 

rate allowed under the tariff for a five-year term should be assured that it will retain its 

rollover rights. TDU Systems contend that the increase in the minimum term from one 

year to five years has mitigated the need for an unlimited matching requirement by 

providing the transmission provider greater certainty in planning its system. TDU 

Systems also contend that transmission providers will not be financially harmed by 

capping the matching requirement at five years since competing rollover customers 

would be subject to price-matching as well. Finally, TDU Systems argue that the “longer 

of” matching policy is unduly discriminatory when applied to requests from transmission 

providers in particular, since they are able to request transmission service for 

unreasonable terms that no transmission customer could prudently match. 
Docket No. RM05-17-001, et al. - 352 -

663. Ameren and Powerex propose other modifications to the matching process. 

Ameren proposes that customers be required to provide notice of a rollover within 15 

days of a pre-confirmed competing request to prevent the customer from sitting on 

capacity until the end of its notice period. Powerex makes a related request to restrict the 

matching requirement to bona fide competing commitments to take such service, such as 

by requiring competing requests to be pre-confirmed or requiring the execution of 

contingent service contracts. Powerex contends that, without such a restriction, a 

customer wishing to roll over its service could be required to match requests in the queue 

for a longer duration that ultimately may not come to fruition. Powerex also asks that the 

Commission clarify that, in cases where a long-term customer that has exercised its 

rollover right is “trumped” by a longer-duration competing request for a lesser quantity, 

the rollover of the original request should be displaced only by the quantity needed to 

fulfill the longer-term, lesser MW request. Powerex argues that no commenter opposed 

this proposal and that the Commission did not provide any rational basis for its rejection 

in Order No. 890. 

Commission Determination

664. The Commission affirms the decision in Order No. 890 not to eliminate the 

requirement to match competing requests in order to retain rollover rights. Longstanding policy requires transmission customers, at the time of rollover of their contracts, 

to match competing requests for service as to term and rate. We disagree with petitioners 

who claim that the requirement of a five-year minimum contract term, or the terms of 

FPA section 217, necessitate any change to our matching policy. The same rationale for 
Docket No. RM05-17-001, et al. - 353 -

the matching policy articulated in Order No. 888 and its progeny with regard to the 

original rollover right applies with equal force to the reformed rollover right. That is, the 

matching policy provides a mechanism not only for awarding capacity to those who value 

it most, but also for breaking ties.261 We do not see how a change to a five-year 

minimum contract term diminishes the need for, or the efficacy of, such a mechanism. 

665. As we noted in Order No. 890, absent the requirement that a customer match the 

term of a competing request, transmission providers could be forced to enter into shorterterm arrangements that could be detrimental from both an operational standpoint, 

including system planning, and a financial standpoint.262 While it is true that the 

extension of the minimum rollover term from one to five years will otherwise enhance 

the transmission provider’s ability to fulfill its planning and construction obligations, it 

does not follow that the transmission provider should be required to forgo the operational 

and financial certainty of an even longer-term competing request at the time of a rollover. 

By awarding capacity to the customers that value it the most, the matching requirement 

benefits all longer-term customers, whether LSEs or other classes of customers, and is 

therefore fully consistent with the requirements of FPA section 217. 

666. We reiterate our existing policy that, in the event of competing, mutually exclusive 

requests for network resource designations, the network customer seeking rollover must 

 261 See Order No. 888-A at 30,197. 

262 See Order No. 890 at P 1255 (citing Order No. 888-A at 30,197). 
Docket No. RM05-17-001, et al. - 354 -

match the term of the competing network resource power contract.263 However, we agree 

with TAPS that, given the differing nature and obligations of network service versus 

point-to-point service, a network customer seeking rollover of its network service for a 

designated resource should be able to match a competing point-to-point request by 

extending its network service agreement rather than the power contract supporting the 

network resource designation.264 We also clarify, in response to Powerex, that a 

customer exercising a rollover right is only required to match a bona fide competing 

commitment to take service, evidenced for example by a pre-confirmed transmission 

request or the execution of a contingent service contract. We disagree with Ameren, 

however, that the transmission provider should be permitted to effectively shorten the 

customer’s notice period by requiring the rollover customer to match a competing request 

prior to the date by which its rollover notice would otherwise be required. 

667. With these clarifications, we continue to believe that it is not unreasonable to 

require network customers to match competing requests for their capacity, even if made 

by marketers in order to engage in resales of capacity or by the transmission provider 

itself. Matching ensures that the customers that value the capacity the most are awarded 

the capacity. In any event, we believe it unlikely that a network customer would be 

routinely faced with viable competing requests from a point-to-point customer seeking 

 263 See WPPI 84 FERC at 61,655-56. 

264 Any subsequent request to designate a network resource would remain subject 

to the requirements of the pro forma OATT, as with any other request to designate a 

network resource. 
Docket No. RM05-17-001, et al. - 355 -

service at the time of the rollover because of the significant differences between network 

transmission service (under which loads and resources are designated, but not specific 

points of receipt and delivery) and point-to-point service (under which such points are 

required to be designated). 

668. We disagree with APPA’s suggestion that rollover customers should be relieved of 

having to match competing requests because the transmission provider is planning and 

upgrading its system on the assumption that the rollover customer will continue service. 

The matching requirement only arises if there are competing requests, i.e., 

notwithstanding any upgrades constructed or planned, capacity will not be available to 

serve both the rollover customer and the competing customer. If there is a bona fide

request from a competing longer-term customer, it is reasonable to expect the rollover 

customer to match the request in order to ensure that capacity is awarded to the customer 

that values it the most. 

669. Finally, we further clarify in response to Powerex that, in cases where a rollover 

customer loses service to a longer-duration competing request for a lesser quantity, the 

rollover of the original request should only be displaced by the quantity needed to fulfill 

the longer-term request for a lesser quantity. In such instances, the transmission provider 

should grant service to the competing customer and reduce the amount of capacity 

available for roll over by the original customer accordingly. 
Docket No. RM05-17-001, et al. - 356 -

d. Rollover Restrictions Based On Native and Network Load 

Growth

 Requests for Rehearing and Clarification

670. TDU Systems ask the Commission to eliminate the ability of transmission 

providers to restrict other LSEs’ rollover rights based on forecasts of the transmission 

provider’s retail and wholesale native load growth. TDU Systems argue that extending 

the minimum term to qualify for rollover rights effectively provides the transmission 

provider five years of notice that it will need to construct transmission upgrades to serve 

its native load growth. Thus, TDU Systems contend, there is no justification for that 

transmission provider to fail to build to meet its service obligation within this period. 

TDU Systems further contend that permitting a transmission provider to avoid its 

obligation to build for its known native load growth by curtailing an LSE customer’s 

rollover rights gives an undue preference to the transmission provider’s native load and 

violates the Commission’s comparability principle. TDU Systems argue this also violates 

FPA section 217(b), which it contends does not distinguish between the transmission 

provider’s native load and the native load of other LSEs. 

671. If the Commission does not eliminate the ability of the transmission provider to 

restrict rollover rights based on its own forecasted load growth, TDU Systems ask, at a 

minimum, that the Commission require transmission providers to treat the load growth of 

other LSEs with native load service obligations in the same manner as the transmission 

provider’s own native load growth. NRECA makes a similar request, arguing that 

comparability requirements and FPA section 217 should place the service obligations of 
Docket No. RM05-17-001, et al. - 357 -

all LSEs on an equal footing. NRECA asks the Commission to confirm that a 

transmission customer using rollover rights to serve native load enjoys the same priority 

as a transmission provider serving its own retail native load and will be factored into any 

native load growth forecasts. 

672. By contrast, South Carolina E&G and South Carolina Regulatory Staff argue that 

the Commission should expand the ability of transmission providers to restrict rollover 

rights. South Carolina Regulatory Staff asks the Commission to ensure that native load 

growth is not marginalized by new non-native customers. The South Carolina 

Regulatory Staff expresses concern that native load service may be forced to yield to 

other service if the transmission provider’s native load forecasts turn out to be wrong. 

South Carolina E&G agrees, arguing that limiting the ability of transmission providers to 

restrict rollover rights only in the initial service agreement puts service to native load at 

an unreasonable risk. South Carolina E&G requests that transmission providers be 

allowed to add rollover restrictions at the time of each rollover (rather than only at the 

initiation of service) to reflect changes in load growth forecasts. 

673. Alternatively, South Carolina E&G suggests that the Commission provide for a 

procedure that would allow the transmission provider to terminate rollover rights when 

new facility construction is required during system planning, i.e., at any point the 

transmission provider determines that a new facility is necessary to accommodate a new 

request or projected native load growth, given the possibility of full rollover by eligible 

customers. South Carolina E&G proposes that transmission providers be required to 

promptly give notice of that determination, which would trigger a limited period of time 
Docket No. RM05-17-001, et al. - 358 -

(e.g., 30 days) for each long-term customer to indicate whether it desires to rollover its 

current contract for another designated period of time. Absent such election by the 

customer within the designated time, South Carolina E&G proposes that the customer’s 

rollover rights be terminated. South Carolina E&G argues that this proposal would 

provide at least partial protection against the inequitable prospect of being forced to 

construct facilities that would be needed in the event of full rollover of service, only to be 

left “high and dry” by a customer’s failure to exercise its rollover rights. South Carolina 

E&G argues its alternative proposal would ensure that native load does not subsidize the 

customer seeking rollover. 

674. If the Commission declines to modify its rollover policies, South Carolina E&G 

suggests the adoption of a native load curtailment priority to ensure that continued 

service to the rollover candidate does not impinge on native load service. Specifically, 

South Carolina E&G states that point-to-point customers could receive rollover rights, 

but if curtailment is required, then that rollover contract (like all other point-to-point 

contracts) would be curtailed before native load. South Carolina E&G also asks the 

Commission to provide greater specificity regarding the meaning of the statement in 

Order No. 890 that, in forecasting native load growth, consideration should be given to 

state-approved integrated resource plans that show a native load need for the capacity. 

South Carolina E&G asks the Commission to specify whether such a plan would be a 

determining factor in the Commission’s evaluation of a transmission provider’s native 

load growth forecast, how much weight the Commission would place on the existence of 

such a plan, and whether the plan would need to incorporate specific elements. 
Docket No. RM05-17-001, et al. - 359 -

Commission Determination

675. The Commission continues to believe it is appropriate to require that rollover 

restrictions be based on reasonable forecasts of native load growth or preexisting 

contracts that commence in the future and that such restrictions be included in the initial 

transmission service agreement. As explained in Order No. 890, this will remain the only 

appropriate way to restrict a rollover right.265 We are not persuaded by petitioners’ 

arguments that the requirement of a five-year minimum contract term, or the native load 

protections found in FPA section 217, necessitates any change to this policy. The same 

rationale for this policy articulated in Order No. 888 and its progeny with regard to the 

original rollover right applies with equal force to the reformed rollover right.266 

676. We disagree with TDU Systems that extending the minimum term to five years 

justifies eliminating the ability of the transmission provider to restrict a customer’s 

rollover right. The transmission provider is allowed to restrict a rollover right in favor of 

its reasonably forecasted native load growth in order to ensure that capacity that exists on 

the provider’s system, at the time of entering into a contract with a customer seeking a 

rollover right, can be recalled for the use of its reasonably forecasted native load growth 

at some time in the future. Our longstanding policy, which was not changed by Order 

No. 890, permits transmission providers to reserve existing capacity for the use of its 

reasonably forecasted native load growth. 

 265 See Order No. 890 at P 1256. 

266 See Order No. 888 at 31,694; Order No. 888-A at 30,198. 
Docket No. RM05-17-001, et al. - 360 -

677. Arguments that the transmission provider has more time to plan for upgrades to 

meet its native load growth because of the new five-year minimum contract term miss the 

point. A transmission provider should not be forced to allow rollover where, at the time 

of entering into a five-year transmission contract with a customer for existing capacity, it 

can show that it will need to reclaim that capacity to serve its reasonably forecasted 

native load growth. Customers that are denied rollover rights may nonetheless secure 

transmission service by submitting service requests for the period in question and 

committing to fund any necessary upgrades. 

678. Alternatively, TDU Systems and NRECA ask the Commission to require 

transmission providers to treat the load growth of other LSEs with native load service 

obligations in the same manner as the transmission provider’s own native load growth 

during forecasting. This is already our policy. In Order No. 888-B, the Commission, in 

addressing a transmission provider’s ability to recall capacity needed for native load 

growth, clarified that “network transmission customers are afforded the same treatment as 

the transmission provider on behalf of native load (retail and wholesale requirements 

customers) in terms of the reservation of existing transmission capacity by the 

transmission provider.”267 This ensures that the LSE’s native load is treated the same as 

the transmission provider’s native load at the time a rollover restriction is considered. 

679. We reject the argument of South Carolina E&G and South Carolina Regulatory 

Staff that the Commission should expand the ability of transmission providers to restrict 

 267 See Order No. 888-B at 62,084-85. 
Docket No. RM05-17-001, et al. - 361 -

rollover rights by, for example, allowing rollover restrictions to be added at the time of 

each rollover (rather than only at the initiation of service) or when the need for new 

facilities arises. We continue to believe that requiring transmission providers to 

determine at the initiation of service whether they have a reasonably forecasted native 

load growth need for the capacity strikes a reasonable balance between the transmission 

provider’s needs and those of its customers seeking long-term transmission service with a 

rollover right.268 If we were to allow the transmission provider the ability to seek to 

restrict a rollover at the time of each rollover, as suggested by South Carolina E&G, it 

would vitiate the benefit of the rollover right to transmission customers, many of which 

also have load-serving obligations. We note, however, that South Carolina E&G’s 

concerns should be mitigated going forward since our requirement of a five-year 

minimum contract term, as well as the one-year notice period and the other rollover 

reforms, will ensure greater consistency between the rights and obligations of customers 

and the planning and construction obligations of transmission providers. 

680. We also decline to adopt South Carolina E&G’s suggestion that point-to-point 

customers with rollover rights be curtailed before native load. The Commission has long 

required that firm point-to-point customers share the same curtailment priority as network 

 268 In addition, we believe that putting the onus on the transmission provider to 

determine the limitations of its system and its own native load growth needs at the time of 

the initial service agreement appropriately allocates responsibility and encourages 

accuracy. Allowing transmission providers the ability to reevaluate their native load 

growth needs on an ongoing basis, or to escape obligations to serve rollover customers 

when upgrades are identified, would tend to discourage a thorough review upfront. 
Docket No. RM05-17-001, et al. - 362 -

customers and the transmission provider serving native load except in the limited 

circumstance when it would require the shedding of bundled retail load.269 Nothing in 

our changes to rollover policies justifies modifying that requirement. We also decline to 

determine generically the weight to be given to state-approved integrated resource plans 

in the determination of reasonable native load restrictions. The determinative factors in 

each case will be identified based on the record, along with the relevant particular 

supporting documentation to be considered. 

e. Effectiveness Upon Acceptance of Coordinated and 

Regional Planning Process

 Requests for Rehearing and Clarification

 

681. Duke argues that the rollover reforms should be implemented immediately and not 

upon acceptance of the transmission provider’s planning process compliance filing. 

Duke contends that the Commission unambiguously found that the prior rollover policy 

was no longer just and reasonable and not unduly discriminatory. Duke also argues that 

the prior rollover policy is inconsistent with FPA section 217, suggesting that the prior 

policy conflicts with the reasonable needs of LSEs to satisfy their service obligations. 

Duke therefore argues that it is not reasonable for the Commission to allow its prior 

rollover policies to remain in place pending acceptance of the transmission planning 

process compliance filings. Duke contends that the Commission did not base its finding 

that rollover policies were in need of reform on the lack of transmission planning 

 269 See Northern States Power Co., 89 FERC ¶ 61,178 (1999). 
Docket No. RM05-17-001, et al. - 363 -

processes and, therefore, making one conditioned on the other is unsupported. 

682. TAPS requests clarification of the timing of compliance filings implementing the 

new rollover policies. TAPS questions whether transmission providers were required to 

submit conforming changes to section 2.2 in their initial compliance filings or as part of 

the Attachment K compliance filings due at a later date. If the former, TAPS states that 

transmission providers would be deleting the current language that will still be in effect. 

TAPS suggests that changes to section 2.2 not be made until the Attachment K is 

accepted. 

Commission Determination

683. The Commission denies rehearing of the determination to tie the effectiveness of 

rollover reform to the acceptance of the transmission provider’s coordinated and regional 

planning process required under Order No. 890. As the Commission explained in Order 

No. 890, reforms regarding rollovers and transmission planning must proceed together 

because they are closely related. Under our longstanding policy, transmission service 

eligible for a rollover right must be set aside for rollover customers and included in 

transmission planning. Duke is therefore incorrect in suggesting that the Commission did 

not rely on our planning-related reforms when fashioning a remedy to ensure rollover 

policies remain just and reasonable and not unduly discriminatory. 

684. With regard to TAPS’ concern regarding the timing of compliance filings 

implementing the new rollover policies, we reiterate that the previously existing rollover 

provisions will remain in effect for the transmission provider until such time as the 

Commission accepts the transmission provider’s Attachment K compliance filing. 
Docket No. RM05-17-001, et al. - 364 -

Accordingly, it is only after a transmission provider’s Attachment K planning process is 

accepted by the Commission that the transmission provider should file the rollover 

reform language, and the effective date of that language should be commensurate with 

the date of that filing. We have revised section 2.2 of the pro forma OATT to make this 

clear. 

f. Transition Issues

 Requests for Rehearing and Clarification

685. Great Northern seeks clarification, or in the alternative rehearing, regarding how 

rollover reform would apply to transmission service requests that were made before the 

issuance of Order No. 890 in reliance on the prior version of section 2.2 of the pro forma

OATT. If Order No. 890 is implemented in such a way as to require a minimum fiveyear contract term in order for rollover rights to attach to pending transmission service 

requests, Great Northern contends it would cause significant disruption in the 

development and financing of competitive generation projects already in the queue. 

Great Northern suggests that requiring pending projects to submit new contracts for fiveyear terms in order to obtain rollover rights in turn would require it to restart its project 

planning process for each of those projects. 

686. Great Northern therefore asks the Commission to confirm that the current one-year 

contract commitment right of first refusal rule will continue to apply to transmission 

service requests that were made prior to the issuance of Order No. 890 and that the fiveyear contract commitment right of first refusal rule will not apply until the first rollover 

date after both the executed transmission service contract and revised section 2.2 of the 
Docket No. RM05-17-001, et al. - 365 -

transmission provider’s pro forma OATT have become effective. If the Commission is 

not inclined to make such a generalized determination in this proceeding, Great Northern 

requests the Commission to rule that, in the specific circumstances where a customer has 

requested transmission service for one year with rollover rights as described in section 

2.2 of the OATT, and thus the transmission provider was on notice of the potential need 

to exercise rollover rights, it will allow rollover rights to apply until the first rollover date 

after both the executed transmission service contract and revised section 2.2 of the 

transmission provider’s OATT have become effective. 

687. NCEMC, NRECA, and TDU Systems request that the Commission clarify that a 

transmission customer will be permitted to rollover an existing contract one time at the 

current terms and conditions following the effective date of Order No. 890, as this would 

avoid any impairment of the contracts entered into by parties prior to the Commission’s 

change in rollover rights policy, consistent with Mobile-Sierra requirements.270 By 

granting one rollover with the same terms and conditions following the effective date of 

Order No. 890, these petitioners assert that the Commission will permit the parties to 

fulfill all obligations under their previously-negotiated transmission contracts and then, 

following this rollover, enter into new transmission and power supply contracts with full 

knowledge of the Commission’s new rollover policy. They contend that certain preamble 

language could be understood to permit a customer to rollover a contract one time at the 

 270 Citing United Gas Pipe Line Co. v. Mobile Gas Services Corp., 350 U.S. 332 

(1956); Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956). 
Docket No. RM05-17-001, et al. - 366 -

currently-effective terms and conditions following the effectiveness of the rollover 

reforms,271 whereas reformed section 2.2 suggests that the five-year term requirement and 

notice provision will become effective on the first rollover following effectiveness of the 

rollover reforms.272 

688. TAPS contends that there could be confusion stemming from the language in the 

Order No. 890 version of section 2.2, which states that the “five-year/one-year 

requirement” will apply “on the first rollover date” after Attachment K is accepted. 

TAPS believes this language could be read to require that a customer’s first rollover after 

the effective date of Attachment K must be exercised one year prior to the end of the 

existing service agreement, which is at odds with the Commission’s recognition that 

some contracts may not have a year left on them and therefore the 60-day notice should 

apply to such contracts.273 TAPS suggests specific amendments to section 2.2 of the pro 

forma OATT to more clearly state the process for rolling over service during the 

transition period. 

 271 Citing Order No. 890 at P 1238 (“existing transmission contracts will be 

permitted to roll over under their existing terms until the first such rollover opportunity 

following the effectiveness of the reforms required by this Final Rule.”). 

272 Citing reformed section 2.2 (“[s]ervice agreements subject to a right of first 

refusal entered into prior to [the acceptance by the Commission of the Transmission 

Provider’s Attachment K], unless terminated, will become subject to the five-year/oneyear requirement on the first rollover date after [the acceptance by the Commission of the 

Transmission Provider’s Attachment K].”). 

273 Citing Order No. 890 at P 1267. 
Docket No. RM05-17-001, et al. - 367 -

689. Powerex also asks that section 2.2 be amended to more clearly state the 

Commission’s rollover policies, arguing that discriminatory and anticompetitive practices 

are more likely to occur in areas where the transmission provider retains discretion. 

Powerex suggests that the Commission clarify that customers with existing long-term 

contracts with rollover rights must only provide 60-days prior notice of their desire to roll 

over their capacity and that the rollover may be for a one-year term with no rollover 

rights or a five-year term with rollover rights. TransServ, however, argues that the 

modified notice requirements of section 2.2 should apply only to existing long-term 

agreements set to expire within one or two years of the effective date of the new fiveyear/one-year long-term service requirements. TranServ argues that allowing existing 

customers with longer-term contracts to retain a 60-day notice provision for many years 

into the future would unnecessarily complicate and delay the transmission provider’s 

ultimate conversion of all existing service agreements to comply with the new fiveyear/one-year provisions for long-term firm service. 

690. Ameren and Tenaska ask the Commission to clarify that notice of a rollover given 

prior to the effectiveness of rollover reform would remain subject to the pre-Order No. 

890 rollover polices, including the existing customer’s willingness to accept a term of one 

year (or the term offered by a competing applicant, if longer). 

Commission Determination

691. We agree with Great Northern that requiring a five-year minimum contract term in 

order for rollover rights to attach to pending transmission service requests could cause 

significant disruption to those transmission customers already in the transmission queue 
Docket No. RM05-17-001, et al. - 368 -

at the time of the effective date of Order No. 890. These customers requested service 

believing that they only needed to enter into a one-year contract in order to obtain a 

rollover right. Accordingly, we grant rehearing and revise section 2.2 of the pro forma

OATT to provide that the current one-year contract commitment requirement will 

continue to apply to all transmission service requests that were in a transmission 

provider’s transmission queue as of the effective date of the reforms adopted in Order 

No. 890 (i.e., July 13, 2007). For such transmission requests, the five-year contract 

commitment requirement will not apply until the first rollover date after both the 

execution of the transmission service contract and effectiveness of the revised section 2.2 

for the particular transmission provider. 

692. We disagree with other petitioners, however, that a transmission customer should 

be permitted to roll over any other existing contracts one time at the current terms and 

conditions following the effective date of the rollover reforms. As we explained in Order 

No. 890, “[i]t is only a rollover contract entered into or renewed after the effectiveness of 

rollover reform that must comply with the new rollover provisions.”274 While it is true 

that the customer rolling over service after the effectiveness of the reforms will be 

required to agree to a minimum five-year term to obtain rollover rights for the new 

agreement, this does not impair the customer’s rights or obligations under its existing 

contract. 

 274 See id.
Docket No. RM05-17-001, et al. - 369 -

693. To the extent there is any confusion regarding the discussion in Order No. 890 of 

when the rollover reforms apply to existing customers, we clarify that an existing 

customer must comply with the new rollover reforms at the time of the first rollover of its 

contract occurring after the effectiveness of the rollover reforms for its transmission 

provider, as provided in the revisions to section 2.2 of the pro forma OATT. For 

example, if an existing customer’s contract expires January 1, 2009, and rollover reform 

became effective on January 1, 2008 for its transmission provider, then any contract 

entered into by the customer at the time of expiration of its existing contract on January 

1, 2009 would have to comply with the rollover reforms (e.g., the new contract must be 

for a minimum term of five-years to retain a rollover right and, if so, one-year notice 

must be given to exercise that right at the expiration of the contract). 

694. In response to TAPS and Powerex, we reiterate that a transmission customer with 

an existing contract that seeks to exercise its rollover after the effectiveness of rollover 

reform may exercise this rollover based on the existing 60-day notice rule, in recognition 

of the fact that during this transition period certain customers may not have a year or 

more left on their existing contracts.275 We agree, however, with TranServ that allowing 

existing customers with longer-term contracts to retain a 60-day notice period provision 

for many years in the future would unnecessarily complicate and delay the transition to 

rollover reform. Allowing existing customers to utilize the 60-day notice rule was 

intended largely to address the situation where a given customer does not have a year or 

 275 See id.
Docket No. RM05-17-001, et al. - 370 -

more left on its contract such that it is possible to give one-year notice. This, of course, is 

not the case with existing contracts that have many years left in their terms before 

expiration. 

695. We therefore clarify that the current 60-day notice rule will continue to apply only 

to those existing contracts that have less than five years left in their terms at the time of 

effectiveness of rollover reform for its transmission provider. Any customer with an 

existing contract with five or more years left in its term at the time of effectiveness of 

rollover reform for its transmission provider will be required to give one-year notice of 

whether it intends to exercise its rollover right. We emphasize that, whether an existing 

transmission customer is required to give 60-days or one-year notice when exercising its 

rollover right under its existing contract, the customer must enter into a minimum of fiveyears of service and meet any of the other requirements of the reformed rollover right in 

order to retain a rollover right going forward. An existing customer may rollover its 

service for a term of less than five years, but will not then retain a rollover right for this 

service. We revise section 2.2 of the pro forma OATT to make these requirements clear. 

696. In response to Ameren and Tenaska, we reiterate that notice of a rollover given 

prior to the effectiveness of rollover reform remains subject to the pre-Order No. 890 

rollover policies, including the existing customer’s willingness to accept a term of one 

year (or the term offered by a competing applicant, if longer).276

 276 See id. at P 1238 (“existing transmission contracts will be permitted to roll over 

under their existing terms until the first such rollover opportunity following the 

effectiveness of the reforms required by this Final Rule.”). 
Docket No. RM05-17-001, et al. - 371 -

3. Modification of Receipt or Delivery Points 

697. Pursuant to Section 22 of the pro forma OATT, a transmission customer taking 

firm point-to-point service may modify its receipt and delivery points, i.e., redirect its 

service, on either a non-firm or firm basis. 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).277 The WEQ standards 

include standards addressing requirements for redirects on both a firm and non-firm 

basis, all of which were incorporated by reference into the Commission’s regulations 

except for WEQ Standard 001-9.7, which addressed the impact of redirects on the 

rollover rights of a long-term transmission customer. Order No. 676 directed the WEQ to 

reconsider WEQ Standard 001-9.7 and develop a revised standard consistent with 

Commission policy. 

698. In Order No. 890, the Commission affirmed reliance on the NAESB process to 

develop business practices implementing the Commission’s redirect policy. The 

Commission also determined that the reforms adopted in Order No. 676, in combination 

with the OATT-related reforms adopted in this proceeding, were adequate to ensure that 

transmission providers do not engage in undue discrimination when a customer seeks to 

modify its receipt and delivery points on a firm basis. With respect to the effect of 

 277 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), reh’g denied, Order No. 676-A, 116 FERC ¶ 61,255 (2006), order on reh’g, Order 

No. 676-B, 72 FR 21095 (Apr. 30, 2007), FERC Stats. & Regs. ¶ 31,246 (2007). 
Docket No. RM05-17-001, et al. - 372 -

redirects on rollover rights, the Commission affirmed its policy allowing a redirect of 

firm, long-term service to retain rollover rights, even if the redirect is requested for a 

shorter period. The Commission concluded that a transmission customer should not have 

to choose between maintaining its rollover rights and redirecting on a firm basis. The 

Commission noted, however, that any change to a delivery point would be treated as a 

new request for service for purposes of determining availability of capacity. As a result, 

a redirect right does not grant the customer access to system capacity or queue position 

different from other customers submitting new requests for service. The Commission 

also provided guidance regarding the processing of, and pricing for, redirected service. 

Requests for Rehearing and Clarification

699. MISO seeks rehearing of the Commission’s decision to allow rollover rights to 

follow the redirected service, asking that rollover rights be limited or eliminated 

altogether in the event of a redirect. MISO argues that the Commission’s statement that it 

was simply continuing its existing rollover policy is confusing since the Commission 

found that the current rollover policy was no longer just and reasonable. MISO also 

contends that the precedent cited by the Commission does not support migration of 

rollover rights to a redirected path. Even if the rollover policy were justified under the 

Commission’s precedent, MISO argues that the Commission’s finding that the policy is 

no longer just and reasonable undermines continued reliance on that precedent. 

700. If the Commission decides to maintain rollover rights for redirects, MISO 

proposes the following limitations and requests the Commission to direct NAESB to draft 

its business practices accordingly. First, MISO suggests that the primary path agreement 
Docket No. RM05-17-001, et al. - 373 -

should have a term of at least five years for any rollover rights to attach. Second, MISO 

requests that any redirect must be for firm service for one year or longer. If the redirect is 

for a shorter period, MISO contends that the rollover rights should remain with the 

original path. Third, MISO requests redirected service to terminate on the same date as 

the parent service so as to maintain the timing for execution of rollover rights. Finally, 

MISO suggests that in order to execute a rollover right the redirected service must be 

requested and granted prior to the one-year deadline for the customer to request rollovers 

along the original path. 

701. Bonneville requests a similar clarification of the application of rollover rights to 

redirects. Bonneville argues that a literal reading of the revised pro forma OATT allows 

a long-term point-to-point customer to request redirected service within the last year of 

its service contract, maintain its rollover rights, and apply them to the new points even 

though it is unable to give a year’s notice of intent to rollover at those points. Bonneville 

therefore seeks clarification from the Commission that rollover rights will remain with 

the original points unless the customer redirects service for at least one year. Without 

clarification, Bonneville contends that redirecting customers will have greater rights than 

customers that do not redirect, who must give one-year’s notice. 

702. TranServ also requests clarification regarding the requirement for the rollover 

right to follow the redirect, regardless of the duration of the redirect. TranServ questions 

whether a redirect of a long-term firm service reservation for one day qualifies that 

customer for rollover rights on the redirected service points. TranServ suggests that the 

Commission instead restrict rollover rights on redirected service points to redirects of five 
Docket No. RM05-17-001, et al. - 374 -

years or longer and further require that the redirect be co-terminus with the original 

request being redirected. TranServ argues that more guidance regarding implementation 

of the rollover and redirect policies will facilitate the NAESB standards development 

process. 

703. MidAmerican requests clarification regarding the queuing of service requests as 

applied to redirects. MidAmerican argues that a request to redirect service should not 

result in a release of transfer capability for third-party service requests in the queue, since 

the increase in transfer capability is contingent upon the approval of the redirect request. 

MidAmerican argues that this approach is consistent with the requirement in section 17 

of the pro forma OATT to use the “same system assumptions and analysis applicable to 

any other new request for service, including whether sufficient ATC exists,” when 

analyzing the ability to grant a request for redirected service. 

Commission Determination

704. The Commission denies petitioners’ requests to amend the rights of rollover 

customers to redirect their service. Under section 22.2 of the pro forma OATT, a request 

for a firm redirect must be treated like a request for new transmission service.278 As a 

new request for service, each redirect request is subject to the availability of capacity and 

subject to the possibility that the transmission provider may not be able to provide 

rollover rights on the new redirected path. The transmission provider is required to offer 

rollover rights to a customer requesting a firm redirect only if rollover rights are available 

 278 See Order No. 890 at P 1268. 
Docket No. RM05-17-001, et al. - 375 -

on the redirected path, i.e., to the extent not restricted based on reasonable forecasts of 

native load growth or preexisting contracts that commence in the future.279 

705. As the Commission explained in Order No. 890, rollover rights follow the redirect 

regardless of the duration of the redirect.280 A transmission customer making a firm 

redirect request does not convert its original long-term firm transmission service 

agreement into two short-term service agreements, nor does it lose its rollover rights 

under its long-term firm transmission service agreement.281 At the same time, a customer 

can exercise its rollover right only at the end of the contract. Thus, if a customer with 

rollover rights chooses to redirect its capacity for less than the full remaining term of the 

contract, absent some further request to redirect, the original path will automatically be 

reinstated and rollover rights would remain on only the original path. By contrast, if the 

customer chooses to redirect its capacity until the end of its contract, the customer would 

have rollover rights along only the redirected path, and only to the extent not restricted 

based on native load growth or future contracts along the redirected path. 

706. We therefore reject requests to restrict rollover rights to longer-term redirects. A 

long-term transmission customer may request multiple, successive redirects for firm 

 279 See Order No. 676 at P 51. 

280 Order No. 890 at P 1280. 

281 Id.; see also Commonwealth Edison Co., 95 FERC ¶ 61,027 at 61,083 (2001) 

(explaining that a request to change delivery points on a firm basis for one month, 

followed by a reversion to the original points does not convert the existing long-term firm 

agreement into two separate short-term agreements); American Electric Power Service 

Corp., 97 FERC ¶ 61,207 at 61,905-06 (2001). 
Docket No. RM05-17-001, et al. - 376 -

service. This discretion is limited by the fact that each successive request is treated as a 

new request for service in accordance with section 17 of the pro forma OATT. Each 

request is therefore subject to the availability of capacity and subject to the possibility 

that the transmission provider may not be able to provide rollover rights on the new, 

redirected path.282 If the customer has not been granted rollover rights for a redirect that 

extends to the end of its contract, the redirected service will terminate on the same date as 

the parent service. 

707. We also reiterate that a customer cannot exercise any rollover rights unless it first 

has provided the appropriate notice to the transmission provider. If a customer requests 

and is granted a rollover right prior to the relevant notice deadline (60 days for pre-Order 

No. 890 agreements or one year for all others) and subsequently requests and is granted a 

redirect for firm service for the remainder of the contract term (i.e., within the notice 

period), the new reservation governs the rights at the new receipt and delivery points and 

the customer can obtain rollover rights with respect to the redirected capacity to the 

extent rollover rights are available for the redirected points. If, however, a customer fails 

 282 For example, assume a transmission customer with a five-year agreement for 

firm service between points A and B, who qualifies for rollover rights on that path. If the 

transmission customer seeks to redirect on a firm basis in year 3 to points C to D and then 

redirect back to points A and B thereafter, at the end of the five year agreement the 

transmission customer would have rollover rights only with respect to points A to B. If, 

however, the transmission customer seeks to redirect to points C and D for the last six 

months of the contract term and both qualifies for rollover rights on this path and has 

requested rollover within the notice period of the contract, the customer would then have 

rollover rights only with respect to points C and D. See Order No. 676 at P 59. 
Docket No. RM05-17-001, et al. - 377 -

to request a rollover right prior to the relevant notice deadline, the customer forfeits 

rollover rights along the current or any redirected path. 

708. We clarify, to the extent necessary, that transfer capability is not freed up for 

earlier queued service requests until a redirect has been granted. A redirect request must 

be evaluated in accordance with section 17 of the pro forma OATT using the same 

system assumptions and analysis applicable to any other new request for service, 

including whether sufficient ATC exists to accommodate the request.283 If there is 

insufficient ATC to offer service to customers in the queue, and an existing customer 

requests redirected service, any increase in ATC along the original path is contingent 

upon the acceptance and confirmation of the redirect. It cannot be assumed at the time of 

a redirect request that the transmission provider will grant the request. 

4. Acquisition of Transmission Service

a. Processing of Service Requests

(1) Posting Performance Metrics

709. To enhance the transparency of the study process and shed light on whether 

transmission providers are processing studies in a timely and non-discriminatory manner, 

Order No. 890 required all transmission providers, including RTOs and ISOs, to post on 

their OASIS sites certain metrics that track their performance in processing system 

impact studies and facilities studies associated with requests for transmission service. 

Specifically, the Commission required all transmission providers to post on a quarterly 

 283 Order No. 890 at P 1285. 
Docket No. RM05-17-001, et al. - 378 -

basis performance metrics associated with: processing time from initial service requests 

to the offer of a system impact study; system impact study processing time; service 

requests withdrawn from the system impact study queue; processing delays for system 

impact studies caused by transmission customer actions; processing time from completed 

system impact study to the offer of a facilities study; facilities study processing time; 

service requests withdrawn from the facilities study queue; and, processing delays for 

facilities studies caused by transmission customer actions. The Commission required 

transmission providers to begin tracking these performance metrics upon the effective 

date of Order No. 890 and keep the quarterly performance metrics posted on their OASIS 

sites for three calendar years. 

710. The Commission also required transmission providers, including RTOs and ISOs, 

to submit a notification filing to 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. 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. Absent a determination from the Commission that delays were due to 

extenuating circumstances, the transmission provider is required to post additional 

metrics regarding the average number of hours expended on, and the number of 

employees dedicated to, system impact studies and facilities studies. Unless otherwise 

directed by the Commission, the transmission provider must begin posting the additional 

performance metrics the quarter following the notification filing. 
Docket No. RM05-17-001, et al. - 379 -

711. The Commission delegated to NAESB the responsibility for developing the 

Standard and Communications Protocols, business practices and OASIS modifications 

that will be necessary to implement the performance metrics. 

 Requests for Rehearing and Clarification

712. Two transmission providers object to aspects of the standard performance metric 

posting requirements. Ameren objects to the requirement that RTOs post these metrics, 

arguing that the requirement may increase an RTO’s cost even though it is unnecessary 

for the efficient operation of competitive markets. Ameren argues that RTOs are by 

definition independent entities that lack the incentive to favor any transmission customer 

over another and, therefore, the performance metrics will serve no purpose in uncovering 

potential discrimination in the study request process. Ameren argues that information 

already posted by MISO and other RTOs allows the Commission to obtain the data it 

seeks without placing additional requirements on RTOs. 

713. Old Dominion argues that the Commission should include in the standard 

performance metrics any denials or delays in the construction phase of transmission 

service requests, suggesting that review of whether requested transmission service is 

effected through construction of identified upgrades and other facilities is a logical and 

necessary outgrowth of Order No. 890.284 Old Dominion asks the Commission to require 

transmission providers to add to the standard performance metrics: the time period of 

 284 Old Dominion also argues that the Commission should require performance 

reports regarding transmission planning activities, which the Commission addresses in 

section III.B. 
Docket No. RM05-17-001, et al. - 380 -

any such postponement or delay; the MW amount of congestion caused by the delay, if 

any; the amount of transmission rights underfunding caused by the delay, if any; and, 

whether the delay resulted in any degradation of system reliability. Old Dominion 

contends that the progress of each project is essential for transmission providers to 

determine whether transmission service requests can be accommodated and whether a 

transmission project is actually constructed or not has an effect on the study process for 

subsequent projects in the queue. 

714. Other transmission providers object to the aspects of the additional performance 

metrics triggered by consistently processing studies outside the 60-day due diligence 

deadline. Washington IOUs ask that the Commission require transmission providers to 

post information on employees and employee-hours devoted to study processing only if 

the Commission first determines that delays in processing study requests are not excused 

by extenuating circumstances. Washington IOUs contend that the Commission’s 

requirement, in Order No. 890, to calculate and post this additional information will 

create a significant additional burden and fails to recognize that the 60-day window is a 

target, not a deadline. They further contend that customers may ask that additional time 

be taken in the processing of studies. Absent a determination that delays in processing 

study requests are a result of a lack of good faith and due diligence on the part of the 

transmission provider, Washington IOUs argue that there should be no requirement to 

track and post employees and employee-hours devoted to study processing. 

715. Washington IOUs also ask that the Commission not count transmission requests 

submitted as part of a transmission provider’s Integrated Resource Planning (IRP) 
Docket No. RM05-17-001, et al. - 381 -

process in the calculation of percentages of studies performed outside the 60-day 

window. They contend that transmission requests associated with such studies are often 

made years in advance to ensure that transmission for service of long-term load is 

available and can be discussed in the public domain, to allow operational personnel to 

confer with one another on IRP issues in a public forum while adhering to the 

Commission’s standards of conduct, and to ensure that the utility will be able to reserve 

transmission capacity necessary to serve the utility’s native load reliably and in a costeffective manner. Washington IOUs argue that there is no need for studies associated 

with these requests to be performed within the 60-day window. 

716. Southern argues that the Commission should grant rehearing so that studies for 

which the customer has requested or expressly agreed to extend the 60-day study period 

should not be required to be included among those studies considered to be completed 

late. Southern contends that it would be arbitrary and capricious to include studies that 

are “late” due to no fault of the transmission provider (e.g., studies delayed or extended 

due to customer request or action) in the metrics calculations. Southern states that doing 

so could cause the transmission provider to be automatically penalized with additional 

reporting requirements and cross the threshold for which the transmission provider must 

proffer excuses acceptable to the Commission or suffer significant penalties. 

Commission Determination

717. The Commission denies rehearing of the decision in Order No. 890 to require 

transmission providers to post standard performance metrics regarding the processing of 

system impact studies and facilities studies and, for consistently late studies, additional 
Docket No. RM05-17-001, et al. - 382 -

performance metrics regarding the resources dedicated to processing studies. These 

posting requirements are necessary to promote greater market transparency and establish 

important incentives for all transmission providers to complete transmission service 

requests in a timely and transparent fashion. As the Commission explained in Order No. 

890, despite the fact that some transmission providers currently post some information 

related to the processing of transmission service requests on their OASIS, much of the 

public information currently posted by transmission providers lacks transparency, 

accessibility, and consistency.285 

718. We affirm the decision to subject all transmission providers, including RTOs and 

ISOs, to the same reporting requirements. While it may be true that data already posted by 

RTOs and ISOs provides much of the information contained in the standard performance 

metrics, it does not follow that posting the remaining information is unnecessary. The 

independent nature of RTOs and ISOs does not justify relieving them of this particular 

obligation. All transmission providers should be subject to the same posting requirements 

to enhance uniformity and transparency in processing transmission service requests and 

transmission studies. Indeed, to the extent an RTO or ISO is already posting much of this 

information, the incremental burden of posting the remaining information should be 

minimal. 

719. The Commission does not believe it is appropriate at this time to add posting 

requirements regarding denials or delays in the construction phase, as requested by Old 

 285 See Order No. 890 at P 1308. 
Docket No. RM05-17-001, et al. - 383 -

Dominion. While construction delays can affect transmission service start dates, the 

transmission provider will be in communication with the relevant customers regarding the 

status of those projects. The transmission provider is also required to make available 

information regarding the status of upgrades identified in its transmission plan, as we 

discuss in section III.B. We are not persuaded that, based on the evidence before us at this 

time, additional posting requirements for denials or delays in the construction phase of 

transmission service requests are necessary or appropriate. Absent particular evidence to 

the contrary, we believe that other OATT provisions such as section 21.2 and the current 

standard performance metrics adequately protect customers from inappropriate delays or 

discrimination during construction phases. 

720. We also affirm the decision to require any transmission provider that 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 to submit a notification 

filing to the Commission and post additional performance metrics. We disagree with 

Washington IOUs that transmission providers should be required to post these metrics only 

after Commission action on a notification filing. Posting of these additional metrics is not 

required until two months after the notification filing, giving the Commission time to 

consider the extenuating circumstances that prevented the transmission provider from 

processing requested studies on a timely basis. If, upon review of such a filing, the 

Commission finds that delays were caused by extenuating circumstances, the Commission 

will not require the transmission provider to continue to post the additional performance 
Docket No. RM05-17-001, et al. - 384 -

metrics. As a result, we expect transmission providers with legitimate extenuating 

circumstances should not have to post any additional metrics. 

721. Similarly, we decline to exempt, as a general matter, studies that are delayed by 

customer agreement or that are associated with resource planning. The transmission 

provider can explain the circumstances surrounding any particular delay in its notification 

filing, which the Commission will review on a case-by-case basis. The process adopted in 

Order No. 890 is sufficiently flexible to relieve any transmission provider who completes 

more than 20 percent of non-affiliates’ studies outside of the 60-day due diligence 

deadlines for two consecutive quarters from any additional posting requirements, or 

operational penalties, if the Commission finds the delays were due to extenuating 

circumstances. 

722. The Commission grants rehearing to make several typographical revisions to our 

rules implementing these posting requirements. In Order No. 890, the Commission stated 

that short-term and long-term requests for point-to-point service must be aggregated for 

purposes of the posting requirement in order to ease the burden on transmission providers 

and in recognition that many customers requesting short-term point-to-point service are 

unwilling to pay for studies.286 The accompanying regulations, however, stated that 

transmission providers must separately calculate and post metrics for long-term and shortterm requests.287 Upon further consideration, we believe it appropriate to allow, but not 

 286 See id. at P 1309. 

287 18 CFR 37.6(h)(1). 
Docket No. RM05-17-001, et al. - 385 -

require, transmission providers to aggregate requests for long-term and short-term point-topoint service for purposes of the posting requirements. We also clarify that the posting 

requirements apply to all requests for service, including requests for point-to-point service 

and requests to designate new network resources or loads. We have revised our regulations 

to make these requirements more clear. 

(2) Operational Penalties for Late Studies

723. The Commission determined in Order No. 890 that all transmission providers, 

including RTOs and ISOs, would be subject to operational penalties when they routinely 

fail to meet the 60-day due diligence deadlines prescribed in sections 19.3, 19.4, 32.3 and 

32.4 of the pro forma OATT. Absent extenuating circumstances, penalties will apply to 

any transmission provider that continues to be out of compliance with these deadlines for 

each of the two consecutive quarters following a notification filing, described above, 

stating that the transmission provider has not completed request studies on a timely basis. 

A transmission provider will be deemed out of compliance if it completes 10 percent or 

more of non-affiliates’ system impact studies outside of the deadlines prescribed in the pro 

forma OATT. 

724. Operational penalties 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. 

The penalty will be equal to $500 for each day the transmission provider takes to complete 

any system impact study or facilities 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 
Docket No. RM05-17-001, et al. - 386 -

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. 

725. As explained above, the Commission reiterated that transmission providers may 

document and describe in their notification filing any unique complexities that particular 

requests introduce into the study process and that prevent the transmission provider from 

completing a study within the 60-day due diligence timeframe. On review of a notification 

filing, the Commission will waive operational penalties if a transmission provider 

establishes that its non-compliance is the result of extenuating circumstances, including 

factors or events that are truly beyond its control, such as delays caused by the transmission 

customer. The submission of a notification filing documenting extenuating circumstances 

will not, however, suspend the obligation of a transmission provider to process at least 90 

percent of the study requests within the deadlines, until such time as the Commission issues 

a final determination on the notification of extenuating circumstances. 

726. The Commission declined to alter the 60-day study completion timeframe embodied 

in sections 19.3, 19.4, 32.3 and 32.4 of the pro forma OATT. The Commission concluded 

that this timeframe adequately balances the need for expeditious resolution of study 

requests and the need to ensure that the transmission provider can reliably accommodate 

the transmission service reserved. The Commission also found that the penalty regime 

adopted in Order No. 890 protects the transmission provider in the event studies take 

longer to complete due to the new planning requirements or the new requirement to 

consider conditional firm options. 
Docket No. RM05-17-001, et al. - 387 -

727. The Commission determined that revenues associated with operational penalties for 

late studies should be distributed to non-affiliated transmission customers. Transmission 

providers were directed to propose a method to determine how unaffiliated transmission 

customers will receive operational penalty distributions. In the event the transmission 

provider has raised extenuating circumstances in its notification filing, the Commission 

stated that the transmission provider should not distribute its operational penalty while the 

Commission is considering the notification filing. 

Requests for Rehearing and Clarification

728. NorthWestern challenges the application of any operational penalties for late 

processing of studies associated with transmission service requests. NorthWestern 

contends that the most important goal of a system impact study or facility study should be 

the ability to perform an accurate study, not one that is quick, and that the Commission 

cites no record evidence that penalties are necessary to prevent unduly discriminatory 

completion of studies. NorthWestern argues that all transmission providers have a 

financial incentive to complete system impact studies quickly in order to maximize use of 

their transmission systems. In NorthWestern’s view, it is unreasonable for the Commission 

to maintain a 60-day period for processing facility studies for transmission service requests, 

yet allow a 90 day and 180 day timeframe for generator interconnection facility studies 

which may be equally complicated. NorthWestern argues that a study may take longer 

than 60 days for a myriad of reasons and, therefore, section 19.9 of the pro forma OATT 

should be eliminated. 
Docket No. RM05-17-001, et al. - 388 -

729. To the extent the Commission declines to eliminate section 19.9, NorthWestern 

argues that it should be waived for transmission providers that do not have an affiliate that 

could benefit from any delay. NorthWestern states that it is a transmission and distribution 

utility within its Montana service territory without an active power marketing affiliate and, 

as a result, the Commission’s rationale for imposing penalties is not applicable to 

NorthWestern and similarly-situated transmission providers. 

730. Several petitioners ask the Commission to clarify that penalties will be assessed 

only if the transmission provider fails to exercise due diligence in completing studies 

within 60 days. EEI argues that the due diligence standard is sufficient to protect 

customers and, therefore, the Commission’s references to extenuating circumstances and 

events beyond the control of the transmission provider should be interpreted to explain 

some aspects of the due diligence standard, rather than impose a new standard for 

completion of studies. Joined by Progress Energy, EEI asks the Commission to modify 

section 19.9(iii) of the pro forma OATT to explicitly provide that penalties will be assessed 

only if the transmission provider fails to complete 90 percent of its studies for non-affiliates 

within 60 days because of a lack of due diligence or where there are no extenuating 

circumstances. 

731. National Grid seeks similar clarification that the Commission is not moving away 

from the due diligence standard in favor of an excuse-based standard. National Grid argues 

that the requirement that transmission providers provide an affirmative excuse to avoid 

operational penalties for untimely studies is an unexplained departure from precedent and 

inconsistent with the Commission’s reference to the due diligence standard in Order No. 
Docket No. RM05-17-001, et al. - 389 -

890. National Grid states that the Commission found in Order No. 2003 that financial 

penalties were not appropriate for late interconnection studies and, instead, required the 

transmission provider to use due diligence to perform within the specified time frame. 

National Grid argues that the Commission failed to justify use of a different, excuse-based 

structure with monetary penalties in the context of studying transmission service requests. 

732. National Grid, along with the Washington IOUs, opposes an excuse-based standard, 

arguing that the transmission provider may not always have a readily articulated excuse for 

not completing studies on time. National Grid states that transmission providers cannot 

simply hire and fire planning employees or otherwise redeploy other employees as study 

queues expand and contract and that, even if they could, the pool of qualified planning 

engineers is inadequate. Washington IOUs also argue that there are numerous legitimate 

reasons why a transmission provider might not process a study within the 60-day guideline, 

including requests by the transmission customer to delay the study process. 

733. Several petitioners argue that the Commission should extend by 30 days or 60 days 

the period within which studies should be completed. MidAmerican argues that strict 

adherence to the 60-day target will lead to less complete analyses by limiting the 

transmission provider’s ability to coordinate with neighboring systems and regional 

reliability organizations, which may be necessary to understand the full effect of a 

proposed transaction, and forcing the transmission provider to make assumptions regarding 

the impacts of higher queued requests still in study status. E.ON U.S. similarly argues that 

the length of a study is influenced by the size and type of the line or substation upgrade 

required, the limited availability of third-party contractors, and the fact that certain 
Docket No. RM05-17-001, et al. - 390 -

modeling studies can take many weeks to prepare. MidAmerican and E.ON U.S. both 

argue that internal staff limitations further impact the transmission provider’s ability to 

meet the 60-day target. 

734. EEI, MidAmerican, and Southern argue that introduction of conditional firm and 

modified planning redispatch service will complicate the study process, may lead to an 

increase in study volume, and ultimately make the 60-day deadline substantially more 

difficult to meet. EEI and Southern argue that it is arbitrary and capricious for the 

Commission to acknowledge in Order No. 890 that studying the availability of these 

products will place increased burdens on transmission provider without addressing the 

problem by granting transmission providers more time to complete those studies. 

735. MidAmerican, Progress Energy and TranServ request clarification regarding when a 

system impact study is considered complete for purposes of the 60-day due diligence 

deadline. Progress Energy suggests that failure to complete a study within 60 days should 

be measured from the projected start date that is included in the applicable study 

agreement, rather than the date the study agreement is executed, and that the transmission 

provider must clearly explain the extenuating circumstance to the customer. MidAmerican 

suggests that the milestone should be the first submission of the study report to the 

transmission customer because it is customary for transmission providers to provide a copy 

of the system impact study for customers to review, which may lead to additional analysis 

or review of potential issues prior to issuing a final system impact study. If provision of 

the review copy of the system impact study does not satisfy the tariff requirement, 

MidAmerican contends that transmission providers will simply omit customer review and 
Docket No. RM05-17-001, et al. - 391 -

provide final studies, likely resulting in more disputes between customers and transmission 

providers. MidAmerican also argues that any delays that occur as a result of review and 

acceptance of study results due to regional planning process criteria should not subject the 

transmission provider to penalties. TranServ similarly notes that certain system impact 

studies are subject to regional coordination review that is out of its control. TranServ 

contends that a system impact study should be deemed complete when a study report is 

concurrently posted on the OASIS, provided to the customer for review, and provided for 

regional coordination. 

736. Some petitioners ask that the Commission exempt from potential operational 

penalties certain types of studies or otherwise confirm that delays in those circumstances 

will be considered extenuating circumstances. Southern and Washington IOUs ask the 

Commission to make clear that operational penalties will not apply when the transmission 

provider and transmission customer expressly agree to a study schedule providing for a 

study period longer than 60 days. TranServ contends that extension of a study period to 

allow for clustering of multiple requests from the same transmission customer should be 

deemed an extenuating circumstance. EEI suggests that studies of the redispatch or 

conditional firm options be exempted from potential penalties or, at a minimum, that the 

Commission establish a one-year transition period prior to including such studies. 

737. Progress Energy asks that the Commission recognize additional specific examples 

of possible extenuating circumstances, including: prior submitted generator 

interconnection queue requests that impact the same interface as transmission service 

queue requests; multiple transmission service queue requests being submitted within a 60-
Docket No. RM05-17-001, et al. - 392 -

day period; a higher queued request that is withdrawn after it has been accepted which can 

cause a restart on subsequent studies that are underway; and, a major change in 

transmission and generation plans of a local or neighboring system that can cause a restart 

on subsequent studies that are underway. 

738. MidAmerican argues that the Commission should remove the penalty provisions for 

facilities studies requiring major construction or offer customers the option of extending 

the study period without penalty to the transmission provider where a customer has a desire 

for an accurate cost and schedule estimate. MidAmerican contends that the 60-day study 

window is inadequate to fully evaluate all the environmental, cultural, and landowner 

issues to fully determine the optimum route for a new line. Without knowing what route a 

line should take, MidAmerican argues that an accurate cost estimate and schedule cannot 

be prepared for the customer and, in turn, that it is unreasonable to expect a customer to 

sign a service agreement based on a highly variable cost and schedule estimate. 

MidAmerican also suggests that, in cases where the transmission service requests are 

submitted in association with a new generation interconnection request, coordination with 

the generation interconnection queue should be explicitly allowed. MidAmerican states 

that, under the Large Generator Interconnection Procedures, the time required to determine 

the facilities necessary to accommodate a generation interconnection request can exceed 

250 days from the date the interconnection request is submitted. MidAmerican contends it 

is not possible to start the system impact study for the transmission service request until 

after it is known what the topology of the system will be with the new generating facility 

and any associated network upgrades and, therefore, the 60-day target should not apply. 
Docket No. RM05-17-001, et al. - 393 -

739. E.ON U.S. requests clarification of the application of operational penalties to its 

operations in particular. E.ON U.S. states that it has delegated certain tasks, including the 

responsibility to perform system impact studies, to an independent transmission 

organization, i.e., Southwest Power Pool. E.ON U.S. contends that this delegation of 

responsibility is consistent with or superior to the penalties established in the pro forma

OATT since it ensures that studies will be performed in a non-discriminatory manner. In 

the alternative, E.ON U.S. seeks guidance on how, or whether it may influence the length 

of time it takes Southwest Power Pool to complete system impact studies, so that they are 

completed within the 60-day due diligence requirement. E.ON U.S. is concerned that it 

may be responsible for penalties incurred by Southwest Power Pool for failure to complete 

system impact studies for E.ON U.S. while being prohibited from influencing the manner 

in which the studies are performed due to the Commission’s orders regarding Southwest 

Power Pool’s independence. 

740. TDU Systems seek clarification that imposition of an operational penalty on a 

transmission provider for a late study does not foreclose other remedies to compensate for 

any damages arising out of a transmission provider’s lack of due diligence, such as, 

recovery of the incremental cost of purchasing power from the market as well as other 

direct and consequential damages, if the transmission customer can show it is entitled to 

further relief. TDU Systems suggest that the Commission explicitly recognize that a 

transmission provider’s failure of performance sufficient to merit the imposition of an 

operational penalty also falls outside the scope of the indemnification owed by the 

transmission customer to the transmission provider under OATT section 10.2. 
Docket No. RM05-17-001, et al. - 394 -

Commission Determination

741. The Commission affirms the decision in Order No. 890 to subject transmission 

providers to operational penalties when they routinely fail to meet the 60-day due diligence 

deadlines prescribed in sections 19.2, 19.4, 32.3 and 32.4 of the pro forma OATT. As the 

Commission explained in Order No. 890, transmission providers must have a meaningful 

stake in meeting study time frames.288 With the procedural protections adopted by the 

Commission, the new penalties for late study will ensure that transmission providers have 

an adequate financial incentive to exercise due diligence in processing service requests in a 

timely and nondiscriminatory manner. 

742. We agree with petitioners that transmission providers should not sacrifice accuracy 

in order to complete studies within the 60-day due period and that transmission providers 

may already have an incentive to complete studies quickly in order to increase revenues 

from transmission service. This does not mean, however, that it is inappropriate to apply 

penalties in instances when transmission providers repeatedly fail to comply with study 

deadlines without justification. The notice procedures adopted in Order No. 890 give 

transmission providers an opportunity to explain why studies have been completed late. As 

a practical matter, then, late study penalties should only apply to those transmission 

providers unable to justify their repeated failure to meet deadlines. At the same time, the 

possibility of penalties will provide appropriate incentives to ensure that transmission 

providers process studies on a timely and nondiscriminatory basis. 

 288 See Order No. 890 at P 1340. 
Docket No. RM05-17-001, et al. - 395 -

743. In response to concerns regarding application of the due diligence standard, we 

reiterate that sections 19.3, 19.4, 32.3, and 32.4 of the pro forma OATT require 

transmission providers to use due diligence to meet the 60-day study deadline. The 60-day 

due diligence deadline serves as a good measure of a transmission provider’s use of due 

diligence since, in our experience, the vast majority of transmission studies can be 

completed within that period. We recognize, however, that certain transmission studies can 

present challenges or other circumstances may justify a longer study period. The 

Commission therefore adopted rules that allow transmission providers to complete studies 

outside the due diligence deadlines without paying late study penalties. In its notification 

filing, the transmission provider can explain the extenuating circumstances that lead to 

delay and, in turn, demonstrate that it has used due diligence in processing the relevant 

studies notwithstanding its inability to meet the 60-day target. Transmission providers 

should discuss any factors that they believe are relevant, including reasonable resource 

limitations, the accommodation of customer requests (including clustering), inter-regional 

and seams coordination, the scope of particular studies, or fluctuations in study volumes. 

On review of this information, the Commission will waive application of late study 

penalties under section 19.9 of the pro forma OATT as appropriate. We therefore do not 

believe any modification to the language of section 19.9 is necessary. 

744. We also reject requests to create broad categories of extenuating circumstances that 

would exempt transmission providers from late study penalties or related posting 

requirements. Consideration of the particular circumstances causing a transmission 

provider to repeatedly miss study deadlines is best left to a case-by-case analysis. Again, 
Docket No. RM05-17-001, et al. - 396 -

failure to meet the 60-day due diligence deadlines does not lead unavoidably to late study 

penalties, regardless of whether the study is related to the new planning redispatch option 

for long-term point-to-point service, the modified conditional firm option, or any other 

service request. Granting broad exemptions for any particular types of requests would 

undermine the Commission’s ability to gather information regarding the reasons for 

processing delays and, in turn, ensure that those delays are justified under the 

circumstances. 

745. We also decline to automatically waive late study penalties for particular types of 

transmission providers, such as transmission and distribution utilities without a power 

marketing affiliate, as suggested by NorthWestern, or RTOs and ISOs, as suggested by 

MISO. The Commission is concerned about potential discrimination in favor of a 

transmission provider’s affiliated customers as well as discrimination between different 

classes of unaffiliated customers. In response to E.ON U.S., we clarify that delegating to a 

third party the responsibility for conducting transmission studies does not relieve the 

transmission provider of its obligation to ensure compliance with sections 19 and 32 of the 

pro forma OATT. Regardless of whether the third-party service provider is under the 

transmission provider’s control, the agreement governing the relationship between the 

service provider and the transmission provider would establish the service provider’s 

responsibilities and potential liability for failing to meet service obligations. This could 

include, for example, the responsibility to submit notification filings describing any 

extenuating circumstances that keep the contractor from meeting deadlines. 
Docket No. RM05-17-001, et al. - 397 -

746. We disagree that the 60-day due diligence period should be extended simply 

because there is the possibility of penalties in the event of repeated non-compliance. While 

we recognize that the timelines we use in Order No. 890 for processing transmission 

service requests may differ from those we have in place in other settings, the 60-day 

deadlines have been in place for many years. We continue to believe that 60 days is, on 

average, sufficient time to complete most transmission studies. As the Commission 

explained in Order No. 890, and as we reiterate above, transmission providers that are 

delayed due to the addition of the conditional firm option, modification of planning 

redispatch, staffing availability, or any other issues are free to raise those issues in their 

notification filings.289 We appreciate, and in fact intend, that the possibility of penalties 

will create added incentives to complete system impact studies and facilities studies within 

the 60-day due diligence deadlines. It does not follow, however, that the deadlines 

themselves should change. In order for late study penalties to apply, the transmission 

provider would have to be out of compliance for at least three quarters after the reforms 

adopted in Order No. 890 took effect. This gives transmission providers nine months to 

adjust their operations and reallocate resources as necessary to meet its obligation to 

process studies on a timely basis. 

747. In response to MidAmerican and TranServ, the Commission reiterates its current 

policy that transmission studies will be deemed complete at the point when the 

transmission provider returns a final system impact study or facilities study to the 

 289 See id. at P 1345. 
Docket No. RM05-17-001, et al. - 398 -

transmission customer. Drafts of such studies, whether submitted to regional coordinators 

or the transmission customer, do not satisfy this threshold because, by definition, they are 

subject to revision and are incomplete. Allowing study drafts to be considered completed 

for purposes of the 60-day due diligence deadline would undermine incentives to finalize 

such studies, leaving transmission customers with little assurance that their transmission 

requests would be processed in a reasonable time period. We do not mean to discourage, 

however, consultation with customers or regional coordination. To the extent such 

activities lead to delays, they should be explained in the notification filing. The 

Commission clarifies in response to Progress Energy that the 60-day due diligence period 

starts on the day the transmission study agreement is executed unless the transmission 

provider and customer agree on an alternate day for the transmission provider to begin the 

study. While the transmission provider and customer may not alter the length of the study 

period, they can mutually agree as to the day on which the study begins. 

748. Finally, we clarify in response to TDU Systems that payment of a late study penalty 

by the transmission provider falls outside the scope of the indemnification provided by 

transmission customers under section 10.2 of the pro forma OATT. Similarly, assessment 

of a late study penalty would not preclude other claims for damages to the extent the 

transmission provider is liable under relevant legal principles. 

(3) Recovery Through Rates

749. In Order No. 890, the Commission prohibited all jurisdictional transmission 

providers from recovering penalties for late studies from transmission customers. The 
Docket No. RM05-17-001, et al. - 399 -

Commission required non-profit transmission providers to pay late study penalties from 

sources other than the revenue they collect for sales of transmission service. 

Requests for Rehearing and/or Clarification

750. Several petitioners object to the application of operational penalties to RTOs and 

ISOs and request clarification of the manner in which penalties could be recovered by 

RTOs and ISOs. MISO argues that RTOs and ISOs should be exempt from the imposition 

of penalties because the organizations have little or no equity cushion from which to pay 

penalties and often need to obtain operational/technical information from member 

transmission owners, over which they have no control, in order to complete studies. MISO 

argues that, as independent entities, RTOs and ISOs have no incentive to favor one group 

of customers over another and that the Commission’s unsupported reference to competing 

internal priorities or staffing issues is not a reasoned substitute for the undue discrimination 

rationale on which the Commission’s reforms are based. MISO argues that the distinction 

between an RTO and a single system transmission provider is particularly acute for MISO, 

PJM, and Southwest Power Pool, which have been required by the Commission to execute 

seams operating agreements that require the sharing of planning information. 

751. MISO objects to the potential use of funds set aside for salaries or bonuses to pay 

penalties, suggesting that budget cuts are not an appropriate remedy for staffing issues. 

MISO contends that RTOs and ISOs should be allowed to recover penalties in rates. 

MISO states that reliability rules permit RTOs and ISOs to recover their ERO penalties in 

rates and the same should be allowed for operational penalties. MISO acknowledges that 

the Commission allowed transmission providers an opportunity to avoid operational 
Docket No. RM05-17-001, et al. - 400 -

penalties by showing that failure to meet the compliance threshold is due to extenuating 

circumstances, but objects to that process as burdensome. MISO argues that it is unclear 

what circumstances would be considered extenuating, suggesting that some customers 

request service well in advance because they are aware of possible delays in performing 

necessary studies. To the extent the Commission retains financial penalties for RTOs and 

ISOs, it suggests that delays resulting in no harm to the customer should not be included in 

the 10 percent threshold. 

752. EEI, National Grid, and ATCLLC argue that the Commission first should consider 

non-monetary penalties for RTOs and ISOs, such as increased oversight, before assessing 

any monetary penalties. ATCLLC and National Grid contend that using a non-monetary 

enforcement policy for violations of the OATT would more closely mirror the policy 

adopted by the Commission with respect to enforcement of reliability standards, as 

reflected in NERC Sanction Guidelines. National Grid suggests that the Commission not 

take the next step of imposing monetary penalties (whether operational or civil penalties) 

on RTOs or ISOs absent extraordinary reasons, such as repeated or willful violations. 

753. If monetary penalties are assessed on an RTO or ISO, National Grid argues that 

the non-profit status of RTOs and ISOs justifies allowing those entities to recover the cost 

of penalties through rates, provided those costs are allocated to all market participants 

fairly. ATCLLC and Duke, however, oppose recovery of any operational or civil 

penalties in the rates of an RTO or ISO. ATCLLC argues that allowing RTOs and ISOs 

to include penalties in their cost of rendering transmission or market services would 

defeat the purpose of the penalty. In its view, the pass-through of penalty costs would be 
Docket No. RM05-17-001, et al. - 401 -

tantamount to imposing the financial consequences of an action on parties that did not 

commit the violation, that may not have any control over the action causing the violation, 

and who may have been negatively impacted by the violation. Duke asks the 

Commission to clarify that the other sources of money from which RTOs and ISOs must 

pay operational or civil penalties do not include any rates collected from customers, 

including administrative charges, energy charges, or charges for transmission-related 

services. 

Commission Determination

754. The Commission affirms the decision in Order No. 890 to prohibit transmission 

providers from automatically passing through to transmission customers the cost of late 

study penalties. The 60-day due diligence standard is in place to protect customers and it 

would therefore be inappropriate to automatically recover from those customers penalties 

assessed for non-compliance. We are mindful of the unique operating and budgetary 

concerns of independent transmission providers with respect to their ability to pay late 

study penalties and will keep those concerns in mind when reviewing these transmission 

providers’ notification filings. However, as we explain in section III.C.4.c, it would not 

be appropriate to exempt, on a generic basis, any particular class of transmission 

providers from the requirement to pay operational penalties. 

755. The Commission acknowledged in Order No. 890 that the independence of RTOs 

and ISOs removes incentives to favor one group of customers over another. 

Notwithstanding this independence, competing internal policies or staffing issues could 

lead to particular types of customers being treated differently during the study process. 
Docket No. RM05-17-001, et al. - 402 -

The potential application of penalties for consistently late studies ensure that the proper 

incentives are in place to process request studies in a timely and non-discriminatory 

manner for every customer. The limited ability of an independent transmission provider 

to absorb late study penalties is more appropriately considered when determining the 

penalty, if any, that will apply to an RTO or ISO on review of its notification filing, 

which would not be possible if a blanket exemption were granted.290 

756. As explained in section III.C.4.c, we decline to state here the particular sources of 

funds from which an RTO or ISO should pay any late study penalties ultimately imposed. 

We do clarify, however, the Commission’s statement in Order No. 890 that an RTO or 

ISO may not use revenues from sales of transmission service to pay late study 

penalties.291 It may be the case that an RTO’s or ISO’s only source of funds is from rates 

collected from jurisdictional transmission customers. The Commission’s intent in 

restricting transmission providers, including RTOs and ISOs, from automatically passing 

on to customers the costs of late study penalties was to prohibit those transmission 

providers from designing their rates to accommodate a pass through of the penalties, i.e., 

effectively including penalties in its cost of service. A transmission provider is permitted 

to use revenues previously collected under Commission-approved rates to pay late study 

penalties by reallocating funds as necessary to distribute late study penalty amounts. 

 290 We clarify that, as part of this analysis, we will consider whether the use of 

non-monetary penalties would be appropriate in the circumstances. 

291 Id. at P 1357. 
Docket No. RM05-17-001, et al. - 403 -

757. We clarify in response to MISO that, if the RTO or ISO is unable to identify any 

appropriate funds from which to pay a late study penalty, the Commission will consider 

case-specific cost-recover proposals under FPA section 205. As explained above, such 

proposals should not include mechanisms to automatically pass through to customers any 

penalties approved to the RTO or ISO. 

(4) Clustering Transmission Service Request Studies

758. Although the Commission did not impose, in Order No. 890, a requirement for 

transmission providers to study transmission requests in a cluster, the Commission did 

encourage transmission providers to cluster request studies when reasonable. In 

particular, the Commission directed transmission providers to consider clustering studies 

if requested to do so by a group of transmission customers and the transmission provider 

can reasonably accommodate the request. To that end, the Commission required each 

transmission provider to include tariff language in its compliance filing that describes 

how it will process a request to cluster studies and how it will structure the transmission 

customers’ obligations when they have joined a cluster. 

Requests for Rehearing and/or Clarification

759. TranServ requests clarification that, if the transmission provider receives a large 

number of study requests from the same customer within a short time period with no other 

customer requests commingled, it may be prudent to combine these studies into a clustered 

study group to reduce costs and study queue volumes, even recognizing that such a practice 

would result in an extended study period. 
Docket No. RM05-17-001, et al. - 404 -

Commission Determination

760. In Order No. 890, the Commission required transmission providers to study 

transmission requests in a cluster if the customers involved request the cluster and the 

transmission provider can reasonably accept the request. The Commission did not 

preclude transmission providers from clustering additional request studies if they believe 

it reasonable to do so. Studying transmission service requests in a cluster in some cases 

can create synergistic benefits, simplify complex, interrelated transmission requests, and 

help transmission providers reduce study queue backlogs. To the extent a transmission 

provider wishes to adopt additional procedures governing the clustering of requested 

studies, it may propose such procedures in a filing under section 205 of the FPA 

demonstrating that clustering will be implemented in a timely and non-discriminatory 

fashion. 

761. Although we agree that in certain circumstances the time required to process a 

clustered study group may exceed the time required to study a single transmission 

request, we do not agree that this should be always be the case. As the Commission 

explains above, we will not exempt broad categories of extenuating circumstances, such 

as the clustering of request studies, from the 60-day due diligence deadline. 

(5) Standardization of Business Practices for Study Queue 

Processing

762. The Commission also required transmission providers working through NAESB to 

develop business practice standards to better coordinate transmission requests across 

multiple transmission systems. In order to provide guidance to NAESB, the Commission 
Docket No. RM05-17-001, et al. - 405 -

articulated the principles that should govern processing across multiple systems. The 

Commission further required transmission providers working through NAESB to develop 

business practice standards to allow a transmission customer to rebid a counteroffer of 

partial service so the transmission customer can take the same quantity of service for 

linked transmission service requests across multiple systems. The Commission explained 

that the transmission customer should not be required to take the same quantity of service 

across consecutive transmission service requests and, instead, it should simply have the 

option to do so. 

Requests for Rehearing and Clarification

763. TDU Systems argue that the Commission erred by failing either to mandate 

coordination among transmission providers or to provide the oversight necessary to 

ensure that NAESB effectively addresses the standards and practices for coordination. 

TDU Systems contend that transmission customers have experienced denials of service 

because of differing response times to transmission service requests spanning multiple 

transmission systems and that a lack of coordination among transmission providers 

reduces accountability for potentially anti-competitive denials of service. To the extent 

the Commission relies on business practices by NAESB, TDU Systems contend that the 

Commission must provide clear deadlines for NAESB to complete the development 

process for these business practices. TDU Systems argue that failure to establish 

deadlines in this context, while establishing clear deadlines for the development of ATCrelated standards, is arbitrary and capricious. 
Docket No. RM05-17-001, et al. - 406 -

764. TAPS asks the Commission to articulate more fully the coordination necessary 

between transmission providers when a customer’s request entails use of multiple 

systems. TAPS notes that the Commission refers in Order No. 890 to coordination of 

studies across multiple systems, but that coordination may be unnecessary if one of the 

affected transmission providers conclude that no system impact study is required. TAPS 

contends there is nonetheless a need to coordinate such requests so that the customer is 

not required to confirm service on the no-study system before knowing whether service is 

available on the other piece of the transmission path. 

765. TAPS also requests confirmation that, in the event only one of the transmission 

providers considering a multi-system request determines that a facilities study is 

necessary, the transmission provider whose system impact study did not lead to a 

facilities study must await the completion of the other transmission provider’s facilities 

study prior to requiring the customer to commit to the service or lose its queue position. 

Similarly, TAPS argues that, if both transmission providers find a need to undertake 

facilities studies, the customer should not be subject to different deadlines for entering 

into those facilities studies or committing to service after all of the facilities studies are 

completed. 

Commission Determination

766. The Commission affirms the decision in Order No. 890 to rely on the NAESB 

process to develop business practices to govern the processing of transmission requests 

across multiple transmission systems. We decline to dictate at this time, beyond those 

principles outlined in Order No. 890, the particular practices that must be implemented. It 
Docket No. RM05-17-001, et al. - 407 -

is more appropriate to allow transmission providers working through NAESB, in the first 

instance, to consider how best to ensure coordination across multiple systems. It is also 

appropriate to give NAESB an open timeframe to develop these standards since they must 

be broad enough to account for the complexities of coordinating multi-system transmission 

service requests.292

767. The appropriate forum for TDU Systems and TAPS to raise substantive concerns 

regarding the coordination required for multi-system requests is therefore the NAESB 

process. If concerns remain at the conclusion of this process, transmission providers and 

customers alike can bring them to the Commission’s attention on review of the NEASB 

business practices. 

(6) Additional Processing Proposals

768. In response to commenter requests, the Commission revised section 17.7 of the pro 

forma OATT so that the transmission provider is able to terminate a request for 

transmission service if a customer that is extending the commencement of service does not 

pay the required annual reservation fee within 15 days of notifying the transmission 

provider that it would like to extend the commencement of service. The Commission 

denied a request to require transmission providers to accept or deny in all cases non-firm 

and short-term firm point-to-point transmission service requests solely based on posted 

 292 NAESB has indicated that business practices governing the coordination of 

service requests across multiple transmission systems are in development. The 

Commission requests NAESB to keep us informed regarding the status of developing 

these and other business practices. 
Docket No. RM05-17-001, et al. - 408 -

ATC, explaining that transmission providers should not be discouraged from making 

service available when posted ATC is not accurate. 

Requests for Rehearing and/or Clarification

769. Southern argues that the Commission should revise the amended provisions of 

section 17.7 of the pro forma OATT to ensure that transmission customers cannot escape 

their contractual commitments by simply failing to timely make an extension of service 

payment. Southern contends that the language of section 17.7 of the pro forma OATT 

makes the termination of a customer’s reservation mandatory, while the Commission’s 

discussion of that language in Order No. 890 indicated an intention for such termination to 

be permissive.293 Southern contends that mandating termination in the event of nonpayment would allow customers to easily escape contractual commitments even where the 

transmission provider has reserved the underlying transmission capacity for that customer. 

Southern requests that section 17.7 be revised to state: “If the Transmission Customer does 

not pay this non-refundable reservation fee within 15 days of notifying the Transmission 

Provider it intends to extend the commencement of service, then the Transmission Provider 

may deem the Transmission Customer in breach and may terminate the Transmission 

Customer’s Service Agreement.” 

770. Southern also requests clarification that transmission providers are allowed to study 

and condition a request for extension of service for long-term agreements having a term of 

less than five years. Southern states that, under the prior rollover policy, it was able to 

 293 Citing Order No. 890 at P 1390. 
Docket No. RM05-17-001, et al. - 409 -

condition the continuation of service beyond the contract term so long as the condition was 

stated in the service agreement. Once the rollover reforms become effective and the 

rollover right extends only to contracts of five years or longer, Southern contends that it 

will no longer evaluate service availability beyond the requested term of service during the 

system impact and facility studies. Where such service is not available, Southern contends 

it would not be possible to grant an extension of the commencement date. Southern 

therefore asks the Commission to allow transmission providers to study, and possibly limit, 

all requests for extensions of commencement of service for long-term agreements having a 

term of less than five years. If the Commission declines to grant this request generally, 

Southern argues that such studies at a minimum should be allowed for extensions of 

commencement of service for customers having agreements for planning redispatch or 

conditional firm service. Southern contends there is increased need for continued study 

regarding the availability of those products, as the Commission recognized by allowing a 

two-year reassessment period for the products. 

771. Powerex repeats its request to require transmission providers to respond to shortterm transaction requests based on the ATC quantity posted at the time the request is 

granted. Powerex contends that allowing transmission providers to grant or deny service 

inconsistent with posted ATC encourages transmission customers to always have requests 

pending in the queue and may lead to customers ultimately viewing the transmission 

provider’s actions as discriminatory. Powerex argues that the Commission cited no 

evidence that its proposal would be unworkable, operationally problematic, or inefficient, 
Docket No. RM05-17-001, et al. - 410 -

nor explained how its ruling is consistent with the emphasis placed on accurate, timely and 

consistent ATC postings elsewhere in Order No. 890. 

772. Powerex also repeats a request to modify the language of sections 17.1 and 17.5 of 

the pro forma OATT to give transmission providers the flexibility to grant short-term 

transmission service requirements without performing a system impact study.294 Powerex 

argues that requiring transmission providers to perform system impact studies to evaluate 

short-term service requests imposes deadlines that are often unworkable. Powerex also 

contends that a refusal to modify sections 17.1 and 17.5 would be at odds with the 

Commission’s decision in Entergy Services, Inc.,295 in which the Commission allowed 

Entergy to evaluate short-term requests without performing a system impact study. 

Powerex argues that the ATC-related reforms adopted in Order No. 890 will ensure that 

this flexibility will not impair system reliability. 

Commission Determination

773. The Commission grants rehearing to revise section 17.7 of the pro forma OATT in 

order to define more equitably the rights and obligations of customers failing to make 

timely payment of deposits in order to extend the commencement of service. Upon further 

consideration, we conclude that it would be inappropriate for a transmission customer to 

lose its underlying transmission service agreement simply because it failed to comply with 

 294 Powerex initially raised this issue in the context of the definition of a system 

impact study and, thus, the Commission addressed the argument in section V.D.10 of 

Order No. 890. 

295 Entergy Services, Inc., 101 FERC ¶ 61,169 (2002). 
Docket No. RM05-17-001, et al. - 411 -

the requirements of extending the service commencement date. We believe that it is more 

equitable to require those transmission customers who seek an extension of service, but fail 

to pay the required deposit in a timely fashion, to lose only their option to extend their 

transmission service start date and not the underlying transmission service agreement. 

774. We therefore decline to adopt the language proposed by Southern, since that could 

still result in the transmission customer losing its entire transmission service agreement 

based on a technicality. The revised language of section 17.7 will more appropriately 

resolve Southern’s stated concern about a transmission customer’s use of the 15-day 

deadline in section 17.7 of the pro forma OATT to escape its underlying transmission 

service agreement. If a transmission customer fails to make the appropriate payment to 

extend service, that customer remains obligated to take service under the original terms and 

conditions of the underlying transmission service agreement. 

775. We agree with Southern, however, that transmission providers should have the 

opportunity to consider the ability to provide service in the event of an extension for 

commencement of service. Under prior rollover policies, transmission providers 

considered whether long-term service would continue to be available beyond the original 

requested term during their initial consideration of the request for service, since 

transmission providers were required to identify in the initial service agreement any 

restrictions on the customer’s rollover rights. Once the rollover reforms adopted in Order 

No. 890 become effective, transmission providers will undertake that analysis only for 

contracts with a term of five years or more. Transmission providers should continue to 

have the opportunity to consider the availability of extended service for contracts with 
Docket No. RM05-17-001, et al. - 412 -

terms of less than five years once the rollover reforms become effective. We therefore 

revise section 17.7 of the pro forma OATT to make clear that extensions of service are 

subject to availability. For contracts of five years or longer, we expect that identification of 

any restrictions on rollover rights in the initial service agreement will continue to serve as 

corresponding restrictions on the ability of the customer to extend the commencement of 

service. 

776. We affirm the decision in Order No. 890 not to require transmission providers to 

grant certain short-term transmission service requests based only on posted ATC values. 

Transmission providers are in the best position to determine how much capacity exists on 

their system in real-time and, therefore, it would not be appropriate for the Commission to 

categorically preclude transmission providers from making such short-term allocations on a 

case-by-case basis. We do not wish to preclude transmission providers from making 

service available at times when posted ATC is not accurate. The transmission provider 

nevertheless must act on a non-discriminatory basis when using its discretion to grant 

service when posted ATC is insufficient. As the Commission stated in Order No. 890, the 

transmission provider must log such instances as an act of discretion and post the log so 

that the Commission and customers may monitor the transmission provider’s actions.296

777. We clarify in response to Powerex that sections 17.1 and 17.5 of the pro forma

OATT do not require transmission providers to undertake system impact studies for all 

requests for short-term transmission service. System impact studies are only required if it 

 296 See Order No. 890 at P 1389 (citing 18 CFR 37.6(g)(4)). 
Docket No. RM05-17-001, et al. - 413 -

is necessary to evaluate the impact of the request prior to granting service. While we 

would expect a transmission provider to use its knowledge of its system, including prior 

studies and system assessments, to grant short-term requests when possible, the 

transmission provider must in every instance consider whether a system impact study is in 

fact required to evaluate the request for transmission service, as the very precedent cited by 

Powerex contemplates.297 We recognize that on occasion a study period could exceed the 

length of service requested by a transmission customer and thereby render moot the 

transmission service request. As the Commission explained in Order No. 890, however, 

implementing a generic rule to eliminate or shorten the period for performing system 

impacts could jeopardize system reliability.298 We therefore decline to adopt Powerex’s 

suggested revisions to sections 17.1 and 17.5. 

b. Reservation Priority

(1) Priority for Pre-Confirmed Requests

778. The Commission determined in Order No. 890 that longer duration service requests 

will continue to have priority over shorter duration service requests, with pre-confirmation 

serving as a tie-breaker for requests of equal duration. The Commission further provided 

that pre-confirmed, non-firm point-to-point transmission service requests and short-term, 

 297 See Entergy Services. Inc., 101 FERC ¶ 61,169 at P 9-10 (stating that Entergy 

would have information to evaluate requests for short-term service without a system 

impact study “in most instances” and should not “unnecessarily rel[y]” on system impact 

studies”). 

298 See Order No. 890 at P 1707. 
Docket No. RM05-17-001, et al. - 414 -

firm point-to-point transmission service requests would have priority over non-confirmed, 

non-firm and short-term requests, respectively, of equal duration. Pre-confirmed requests 

for transmission service will not preempt an equal duration request that has already been 

confirmed. 

779. The Commission also clarified its policies regarding the treatment of pre-confirmed 

requests in order to address concerns regarding operational difficulties caused by giving 

priority to such requests. First, the Commission prohibited transmission customers from 

withdrawing pre-confirmed, non-firm and short-term firm point-to-point transmission 

service requests prior to when the transmission customer is offered service or a system 

impact study. Transmission providers shall invalidate, however, a pre-confirmed request at 

the request of the transmission customer in the very near term following submittal of the 

request, in the event the transmission customer makes an inadvertent error in submitting its 

request. Second, the Commission explained that a customer is not bound to take service 

when the transmission provider counteroffers the customer’s initial request, although it is 

obligated to take service in the event the transmission provider offers the service requested. 

Requests for Rehearing and Clarification

780. TranServ objects to the retention of priority for longer-term service, regardless of 

pre-confirmation status. TranServ maintains that the advantages of longer-term services 

in the form of redirect opportunities and secondary market sales are sufficient incentives 

in and of themselves and that the ability to preempt shorter term service is unnecessary to 

promote longer term sales. TranServ acknowledges that the preemption and matching 

provisions have been in the pro forma OATT since Order No. 888, but questions the 
Docket No. RM05-17-001, et al. - 415 -

extent to which they have been fully implemented into the business practices of all 

transmission providers. TranServ argues that transmission customers would prefer to 

have transaction certainty once they have confirmed service instead of remaining in an 

uncertain, conditional state up until the relevant scheduling deadline. TranServ also 

suggests that retention of the preemption policy will impede development of the 

secondary market for transmission capacity, questioning whether customers would see 

any value in entering into a secondary market purchase that is subject to preemption or 

understand their rights and obligations, and those of the assignee, in the event preemption 

occurs. 

781. If the Commission retains the priority for longer term service, TranServ requests 

clarification of how preemption is to be implemented in certain circumstances. TranServ 

questions whether a reservation for consecutive terms of service is considered 

“unconditional” in its entirety when the first increment of service becomes unconditional. 

For a reservation for three consecutive days of daily service, TranServ asks whether that 

entire reservation (three days) is considered unconditional one day prior to the start of 

service, or whether only the first day of that three-day reservation becomes unconditional 

and not subject to preemption. 

782. Ameren maintains that the Commission should include priority for pre-confirmed 

long-term firm requests to ensure that long-term uses are allocated to those customers 

that have the greatest demand. Ameren contends that excluding long-term firm requests 

from consideration as pre-confirmed requests may distort the transmission service queue 

and affect existing long-term firm uses of the grid, such as agreements eligible for 
Docket No. RM05-17-001, et al. - 416 -

rollover rights, by triggering the requirement to match a competing request that has not 

been confirmed. Ameren requests that the Commission require priority for pre-confirmed 

requests of all durations of firm service or, at a minimum, require that any request that 

competes with a long-term firm transmission service agreement eligible for rollover must 

be pre-confirmed. 

783. E.ON U.S. argues that it is not clear what happens to a pre-confirmed request if 

the transmission provider only can provide the requested service if additional facilities 

are constructed. E.ON U.S. requests clarification whether an offer to provide service if 

additional facilities are constructed is a counteroffer that allows the customer submitting 

a pre-confirmed request to decline service. 

784. Tenaska requests additional flexibility regarding the withdrawal of pre-confirmed 

requests. Tenaska suggests that the Commission establish a defined period, up to the 

point prior to the processing of the request by the transmission provider, during which 

pre-confirmed, non-firm and short-term firm point-to-point transmission service requests 

may be withdrawn for any reason and without penalty. Tenaska argues this flexibility is 

necessary to ensure that point-to-point customers are not competitively disadvantaged 

vis-à-vis network service customers when obtaining ATC, since network customers pay 

no additional cost for transmission they cannot use. 

785. Southern suggests that the Commission allow transmission providers working 

through NAESB sufficient time to develop procedures for processing competing preconfirmed requests, including how a request whose evaluation is in progress should or 
Docket No. RM05-17-001, et al. - 417 -

should not be impacted by a new pre-confirmed request received prior to such evaluation 

being completed. 

Commission Determination

786. The Commission affirms the decision in Order No. 890 to give priority based on 

pre-confirmed status only to short-term firm and long-term non-firm requests for service. 

As the Commission explained in Order No. 890, the Commission was mindful that the 

pre-confirmation process could disrupt the transmission study process, undermine longerterm uses of the transmission system, or disadvantage transmission customers that are not 

in a position to pre-confirm their requests. Restricting the scope of transmission service 

requests receiving priority for pre-confirmation status to short-term firm and long-term 

non-firm service requests is necessary in order to minimize disruptions with existing 

study procedures and power procurement practices in place for long-term firm service 

requests. We believe this appropriately balances the need to promote long-term 

transmission rights against the need for increased certainty for customers seeking shorterterm firm and non-firm service.299 Similarly, we decline to alter the Commission’s longstanding policy of giving longer duration requests for service priority over shorter 

duration requests. To do so would undermine the Commission’s goal of encouraging 

longer term uses of the transmission system. 

 299 As we explain in section III.D.2.c, a customer exercising a rollover right is only 

required to match a bona fide competing commitment to take service, evidenced for 

example by a pre-confirmed transmission request or the execution of a contingent service 

contract. 
Docket No. RM05-17-001, et al. - 418 -

787. We clarify in response to E.ON U.S. that, in the event an offer for service on a 

pre-confirmed request can only be accommodated by additions to the transmission 

provider’s transmission system, the transmission customer may: (1) take a shorter term 

of service, if available; (2) agree to undertake any upgrades that may be necessary to 

accommodated the transmission requests; or (3) decline service. The Commission rejects 

Tenaska’s proposal to adopt a deadline prior to which a transmission customer may 

withdraw a pre-confirmed transmission service request. Providing an opportunity to preconfirm applications is intended to reduce overloading of transmission study queues and 

minimize the amount of transmission requests later withdrawn from the study queue, 

increasing the efficiency of processing transmission service requests. Allowing 

transmission customers to withdraw pre-confirmed transmission service requests without 

reason or penalty as suggested by Tenaska would undermine the very reason preconfirmation status has been given a priority. 

788. We decline Southern’s request to extend the effectiveness of the reforms regarding 

pre-confirmation priority pending development of related business practices by NAESB. 

We believe that Order No. 890 provides sufficient guidance for transmission providers to 

implement this priority in advance of any standardization efforts that may be undertaken 

through the NAESB process. 

789. With respect to TranServ’s question regarding application of the right of first 

refusal for eligible customers with requests for service over multiple days, the 

Commission clarifies that a competing request must exceed the total term of service in 

order to trigger the right of first refusal. Thus, in order for a competing request of equal 
Docket No. RM05-17-001, et al. - 419 -

price to preempt a reservation for three conservative days of daily service, that request 

must be for four consecutive days or longer and must be received at least one day before 

the first day of the original customer’s three-day term of service. 

790. Upon review of tariff provisions governing pre-confirmation of transmission 

service requests, the Commission has determined that the language adopted in Order No. 

890 did not fully capture the Commission’s intent of allowing all eligible customers the 

opportunity to pre-confirm short-term firm and non-firm reservations. As currently 

written, the language of sections 1.39, 17.2 and 18.2 of the pro forma OATT make preconfirmation available only to those that are already transmission customers, rather than 

all eligible customers. The Commission has revised those sections of the pro forma

OATT to more accurately reflect our intent that pre-confirmation service should be 

available to all eligible customers seeking short-term firm and non-firm transmission 

services. 

(2) Price as a Tie-Breaker

791. In Order No. 890, the Commission added price as a tie-breaker in determining 

reservation queue priority when the transmission provider is willing to discount 

transmission service, so that price will serve as a tie breaker after pre-confirmation status. 

The Commission clarified that, in the event a later queued short-term request for 

transmission service preempts a conditionally confirmed short-term request for 

transmission service based on price, the conditionally confirmed request has a right to 

match the price offer of the later queued request. 
Docket No. RM05-17-001, et al. - 420 -

Requests for Rehearing and Clarification

792. E.ON U.S. requests clarification that the use of price as a tie-breaker means that a 

customer that is receiving service and that is not otherwise subject to a discount will 

receive a reservation priority over one who receives a discount. E.ON U.S. states that 

transmission service is not provided at market-based rates and, thus, using price as a tiebreaker cannot mean that a customer offering a market-based price is to be rewarded with 

reservation priority. 

Commission Determination

793. We agree with E.ON U.S. that use of price as a tie-breaker does not mean that a 

customer is offering to be charged a market-based rate by the transmission provider. Under 

section 13.2 of the pro forma OATT, price serves as a tie-breaker among competing service 

requests of equal duration only when the transmission provider has offered a discount or a 

“below ceiling rate” on transmission service. Transmission providers may not charge rates 

above those stated in their OATT for primary transmission capacity.300

(3) Five-Minute Window for Requests

794. The Commission determined in Order No. 890 that the first-come, first-served 

policy for transmission service under the pro forma OATT should remain largely intact. 

The Commission allowed, but did not generally require, transmission providers to 

propose a window within which all transmission service requests the transmission 

 300 The Commission addresses the reassignment of transmission service in the 

secondary market in section III.C.3. 
Docket No. RM05-17-001, et al. - 421 -

provider receives will be deemed to have been submitted simultaneously. Only 

transmission providers that have adopted a “no earlier than” time for submitting 

transmission service requests were required to treat transmission service requests 

received within a specified period of time as having been received simultaneously. The 

Commission stated that the submittal window for these transmission providers must be 

open for at least five minutes unless the transmission provider can present a compelling 

rationale to justify a shorter submittal window. The Commission required these and any 

other transmission providers deeming requests submitted within a specified period as 

having been submitted simultaneously to propose a method for allocating transmission 

capacity if requests submitted within the same time period exceed available capacity. 

Requests for Rehearing and Clarification

795. Powerex and Southern protest the Commission’s departure from the long-standing 

first-come, first-served priority scheme. Powerex contends that, of the commenters 

supporting a simultaneous-priority window, none presented evidence that they were less 

sophisticated, had fewer financial resources, or had encountered prohibitively high 

software and other costs associated with operating an efficient transmission reservation 

desk. Powerex argues that the Commission mischaracterized support for the window 

proposal, stating that half of the critics of the proposed window provide and/or use 

transmission predominantly within the Western Interconnection. 

796. Powerex, Southern, and Tenaska suggest that use of a simultaneous priority window 

will lead to implementation and operational problems, requiring transmission providers to 

allocate transmission capacity among multiple requesting customers, resulting in customers 
Docket No. RM05-17-001, et al. - 422 -

potentially receiving unusable blocks of capacity. Powerex contends that the Commission 

has relied on first-come, first-served priority in other contexts based on a similar concern 

that pro rata allocation of scarce capacity may result in blocks too small for the customer to 

use.301 If the Commission does not grant rehearing on this issue, Southern asks the 

Commission, at a minimum, to clarify that NAESB will be permitted to address and 

resolve in a uniform fashion the numerous operational issues associated with treating all 

requests received within a certain timeframe as having been received simultaneously. 

797. Powerex further argues that, with a pro rata window approach, transmission 

customers with multiple affiliates will be able to secure more usable blocks of capacity by 

pooling their requests through reassignment, while single-entity customers will confront 

numerous transaction obstacles to obtain a similar result. Powerex again points to 

precedent in the gas context, arguing that the Commission recognized similar concerns to 

support a first-come, first-served approach for reserving pipeline capacity.302 Powerex 

argues that the Commission failed to address these concerns. Finally, Powerex objects to 

the Commission’s characterization of the first-come, first-served priority structure as 

arbitrary, arguing that a specified window is equally arbitrary since it separates by a 

millisecond those that fall within the simultaneous window and those that fall outside. 

798. If the Commission declines to grant rehearing of the use of a simultaneous priority 

window, Powerex requests clarification regarding its implementation. First, Powerex 

 301 Citing Trailblazer Pipeline Co., 108 FERC ¶ 61,049 (2004). 

302 Citing id. 
Docket No. RM05-17-001, et al. - 423 -

contends that a simultaneous window must commence at the start of the “no later than” 

hour and conclude five minutes later, and not be a “rolling window” that groups together 

service requests submitted within five minutes of each other. Second, Powerex requests 

clarification that the simultaneous priority window would not apply to hourly transmission 

service, to the extent it is offered by the transmission provider, arguing that there is 

insufficient time for customers to monitor the multitude of various transmission providers’ 

windows for hourly requests and that potential pro rata allocations of hourly service would 

have little value to customers. 

799. Tenaska similarly argues that the Commission must provide clear, uniform guidance 

as to what methods will, and will not, be acceptable for allocating transmission capacity 

when there is insufficient capacity to satisfy requests deemed to have been submitted 

simultaneously, as well as further guidance regarding the window period that a 

transmission provider may designate. Tenaska contends that the Commission has given 

transmission providers too much discretion by allowing them to propose a method for 

allocating transmission capacity if sufficient capacity is not available to meet all requests 

submitted within the specified time period. Tenaska argues that such discretion is a 

potential breeding ground for undue discrimination and, therefore, that the Commission 

should provide additional guidance to ensure that the methods for allocating transmission 

capacity minimize the opportunity for gaming. 

800. Ameren asks the Commission to clarify that any proposal to voluntarily adopt an 

equivalent priority standard must be clearly defined and supported. Ameren suggests that 

an applicant submitting a proposal for a five-minute equivalent priority standard must 
Docket No. RM05-17-001, et al. - 424 -

make clear whether it is proposing to use a rolling five-minute window or whether it will 

use a series of discrete five-minute windows. Ameren contends the applicant also should 

be required to clearly explain what sort of tie-breaking mechanisms it will use. 

801. EEI asks the Commission to clarify the requirement to adopt a submittal window is 

not triggered by a “no earlier than” time for requests for non-firm service. EEI notes that 

section 18.3 of the pro forma OATT requires all transmission providers to impose limits on 

how early a request for non-firm service may be submitted. EEI therefore argues that the 

requirement to adopt a submittal window should apply only to transmission providers that 

have established a "no earlier than" time for requests for firm point-to-point or network 

service. 

Commission Determination

802. The Commission denies rehearing of the Commission’s decision in Order No. 890 

to require transmission providers that have adopted a “no earlier than” time for submitting 

requests for firm transmission service to treat all requests received within a specified period 

of time as having been received simultaneously.303 We agree with petitioners that the 

Commission’s long-standing first-come, first-served policy is a simple and efficient way 

for transmission providers to allocate firm transmission capacity among competing service 

requests. For this reason, Order No. 890 generally grants transmission providers the 

 303 We agree with EEI that the requirement to establish a submittal window applies 

to those transmission providers that have adopted a "no earlier than" time for the 

submission of firm point-to-point or network service. The pro forma OATT contains a 

"no earlier than" time that applies to requests for non-firm point-to-point service, which 

we do not intend to trigger the requirement to establish a submittal window. 
Docket No. RM05-17-001, et al. - 425 -

discretion to determine which transmission services, if any, will be subject to a submittal 

window. The Commission recognized only one exception to this rule: when the 

transmission provider has established dates before which requests for firm transmission 

service will not be accepted. 

803. As the Commission explained in Order No. 890, the first-come, first-served policy 

can disadvantage certain transmission customers when a “no earlier than” restriction is in 

place.304 Such a restriction forces transmission customers competing for transmission 

capacity to precisely time their requests for service such that they are received after the “no 

earlier than” time, yet before other customers. This has the potential of disadvantaging 

transmission customers that are less sophisticated and have fewer financial resources. The 

Commission stated in Order No. 890 that, when considering requests for firm transmission 

service received after the “no earlier than” time has expired, there is no meaningful 

difference between those received seconds ahead of another because one customer’s 

computer is slower than another and no petitioner argues otherwise on rehearing.305 

804. We clarify in response to Ameren and Powerex that each transmission provider has 

discretion to determine how its submittal window will be implemented, including the point 

at which the window goes into effect. Although the Commission agrees with Powerex, in 

principle, that it would be logical for submittal windows to begin on the first minute of the 

“no earlier than” time, we will not categorically dismiss alternatives to this arrangement 

 304 See Order No. 890 at P 1419. 

305 Id.
Docket No. RM05-17-001, et al. - 426 -

since these procedures are best reviewed on a case-by-case basis. Similarly, any 

transmission provider that has implemented hourly firm point-to-point service should 

address how the submittal window would be implemented for that service, including any 

limitations on the use of a submittal window for that product. It is more appropriate for the 

Commission to consider customer concerns regarding use of a submittal window for hourly 

firm transmission service in the context of the transmission provider’s particular proposal. 

805. The Commission recognizes that developing methods to allocate capacity among 

requests received during a submittal window may require detailed procedures, particularly 

when transmission requests received simultaneously exceed available capacity. As the 

Commission explained in Order No. 890, however, we believe that each transmission 

provider is in the best position to develop allocation procedures that are suitable for its 

system. This does not preclude transmission providers from working through NAESB to 

develop standardized practices, as suggested by Southern. For example, as we pointed out 

in Order No. 890, allocation methods such as that used by PJM to allocate monthly firm 

point-to-point transmission service could provide useful guidance in developing general 

allocation procedures.306 

806. The Commission disagrees with Tenaska that allowing transmission providers to 

develop a methodology to allocate insufficient capacity will lead to undue discrimination. 

As Ameren suggests, each transmission provider must clearly define and support its 

allocation methodology in its tariff and, thus, customers can raise any concerns regarding 

 306 See id. at P 1422. 
Docket No. RM05-17-001, et al. - 427 -

the potential for discrimination during the Commission’s review of the relevant tariff 

language. Once the tariff language is in place, transmission customers can, and should, 

bring to the Commission’s attention any failure by the transmission provider to follow its 

tariff. While the Commission could remove transmission provider discretion in this area 

by adopting a single, one-size-fits-all approach, such as a mandatory pro rata distribution 

methodology, this approach may not produce the best result in all cases. As the very 

precedent cited by petitioners acknowledges, every allocation methodology has advantages 

and disadvantages.307 We reiterate our belief that transmission providers are in the best 

position to determine which allocation mechanism works best for their systems. 

(4) Right of First Refusal and Preemption

807. The Commission declined in Order No. 890 to otherwise change the “first come, 

first served” nature of the reservation process or right of first refusal process. The 

Commission explained that, when a longer-term request seeks capacity allocated to 

multiple shorter term requests, the shorter-term customers should have simultaneous 

opportunities to exercise the right of first refusal. The Commission also stated that, to 

minimize the potential for gaming, a preempting longer request must be for a fixed 

 307 See Trailblazer Pipeline Co., 108 FERC ¶ 61,049 at P 41. The Commission in 

that case accepted a pipeline’s proposal not to use pro rata allocations in the event tie 

breaking was necessary out of a concern that resulting amounts of capacity would be too 

small to be of real use to a shipper. Shippers, however, had argued for use of pro rata 

allocations to increase the number of parties that could serve a market. Based on the 

circumstances of that case, the Commission accepted the proposal to use a first-in-time 

tiebreaking methodology. It does not follow, however, that use of a pro rata allocation 

would be inappropriate in all circumstances. 
Docket No. RM05-17-001, et al. - 428 -

capacity over the term of the request. The Commission also revised section 13.2(iii) of the 

pro forma OATT to more clearly distinguish between the use of the terms “request” and 

“reservation” for purposes of administering the right of first refusal. 

Requests for Rehearing and Clarification

808. TranServ contends that the Commission did not fully address in Order No. 890 the 

procedures governing the right of first refusal competition and its potential for gaming. If a 

longer-term request initiates a right of first refusal competition among multiple shorterterm customers, TranServ requests clarification of whether there should be rounds of 

bidding and, if so, what the timing of that process should be. TranServ also asks what 

should happen in the event that a longer duration (not pre-confirmed) request is withdrawn 

in the middle of a competition, i.e., whether those customers that opted to match are 

allowed out of their longer duration reservations and whether those that opted not to match 

are re-instated to their original capacity. TranServ suggests that, before any preemptions 

are initiated, the longer duration, higher priority request must be confirmed and locked in 

with the competing customer before turning to the right of first refusal rights holders and 

seeking their intent to match to preserve their service priority. In addition to locking in the 

longer duration customer prior to initiating preemption and right of first refusal, TranServ 

argues that the transmission provider should be required to provide a “counter-offer” 

matching request to the customer being preempted that they may then elect to ignore or 

withdraw, or confirm to retain their service priority. TranServ further questions what the 

transmission provider’s obligation is if the customer being preempted exercises its right of 
Docket No. RM05-17-001, et al. - 429 -

first refusal by submitting a longer duration request which cannot be granted without 

preemption of yet another request. 

809. TranServ also questions implementation of the right of first refusal in the event 

transmission capacity is reassigned. Assuming that a customer with a confirmed 

reservation for one week resells capacity for one day, TranServ asks whether the reseller, 

the assignee, or both have responsibility to match a competing longer-term request received 

by the transmission provider. TranServ states that this issue was considered by NAESB 

during WEQ discussions and that, during those discussions, there was serious consideration 

given to not allowing the resale of short-term firm prior to its unconditional deadline. 

810. TranServ further questions what a shorter-term transmission customer’s obligation 

is if the longer-term service request only preempts a portion of the short-term customer’s 

service. TranServ suggests that the term “match” in such instances be limited to an exact 

match of duration with no option for the preempted customer to go beyond those bounds 

and that the capacity of the match should be in the amount that would need to be recalled 

from the preempted customer to satisfy the longer duration request. 

811. Duke argues that the right of first refusal regime for transactions as short as one day 

for firm and one hour for non-firm is overly complicated and will leave customers 

confused and unsatisfied as to whether and when they can be assured that they have 

secured transmission capacity. Duke provides detailed hypotheticals of the right of first 

refusal competition process, arguing that the process is cumbersome and could lead to 

anomalous and unwarranted outcomes. Duke urges that the Commission place the 

following limits on the right of first refusal: require that matching requests be pre-
Docket No. RM05-17-001, et al. - 430 -

confirmed and at full tariff price, and that they be for the same amount (MW) and duration 

as the competing requests; and, provide that rights of first refusal are only offered when 

there is no impact on reservations that are not on constrained interfaces. With these 

limitations in place, Duke contends that the transmission provider will not have had to 

entertain multiple right of first refusal rounds that in some instances may leave capacity on 

the table and force customers to buy more service than they may have required. 

812. Bonneville seeks clarification as to how duration, pre-confirmation status, price and 

time of response should be used to determine the order in which the multiple, preempted 

shorter-term requests may exercise the right of first refusal. By providing several 

hypotheticals, Bonneville states that it cannot envision a circumstance in which a right of 

first refusal is offered to a request when the transmission provider does not have capacity to 

satisfy that request. Bonneville requests that the Commission either delete the two 

sentences in section 13.2(iii) of the pro forma OATT concerning this issue or clarify how 

the transmission provider is expected to apply them. 

813. Bonneville also requests clarification regarding which customers have a right of first 

refusal under section 13.2 of the pro forma OATT. Although the Commission amended the 

second sentence in section 13.2(iii) of the pro forma OATT to grant eligible customers with 

a “reservation” a right of first refusal to match longer-term “requests,” other sentences in 

that section still refer to preemption of shorter-term “requests” for service instead of 

“reservations.” Bonneville states that this suggests that shorter-term requests maintain a 

right of first refusal. Bonneville also contends that the first sentence of section 13.2(iii), 

providing that “requests” for longer term service may preempt “requests for shorter term 
Docket No. RM05-17-001, et al. - 431 -

service” up to specified deadlines, suggests that a longer duration request simply preempts 

a shorter duration request, which is not offered a right of first refusal. Bonneville argues 

that this would violate the first-come, first-served rule, yet if the longer duration request is 

offered a right of first refusal, it would contradict the amended language of section 

13.2(iii), under which only longer duration “reservations” have a right of first refusal. 

Commission Determination

814. The Commission affirms the decision in Order No. 890 not to change the “firstcome, first served” nature of the reservation process and the right of first refusal. These 

policies have worked well in the past and, as we explain in Order No. 890, benefit 

transmission providers and customers alike by facilitating the administration of the 

reservation process and removing confusion about how to comply. 

815. We disagree with Duke and TranServ that the right of first refusal policies should be 

revised based on complex hypotheticals involving the preemption of multiple short-term 

reservations. The complexities pointed to by these commenters do not by themselves 

warrant changing the right of first refusal rule. Even though we recognize the potential for 

complexities to arise under the right of first refusal rule, we believe them to be relatively 

limited. In the off-chance that multiple eligible customers with short-term reservations 

choose to exercise their right of first refusal for the same capacity simultaneously, the 

Commission believes that they should have a right to do so. 

816. We therefore decline to expand upon the language of the pro forma OATT to 

account for every factual scenario that could arise under sections 13.2 and 14.2 of the pro 

forma OATT. Sections 13.2 and 14.2 of the pro forma OATT set forth adequate guidance 
Docket No. RM05-17-001, et al. - 432 -

for transmission providers to fairly administer competing requests, including the priorities 

for determining which reservations or requests trump one another as well as the timeframes 

for eligible customers to respond to competing requests. As noted above, we recognize 

that certain unique cases can present difficult allocation issues, but conclude that these 

extreme cases arise infrequently in the normal course of business. In the vast majority of 

cases, we believe the right of first refusal rules are efficient and easy to administer without 

further amending the governing tariff language, as Bonneville and Southern suggest. 

817. To the extent necessary, the Commission clarifies that a “competing request” under 

sections 13.2 and 14.2 of the pro forma OATT may include a transmission service request 

that overlaps with only part of another existing transmission service reservation since both 

requests cannot be granted simultaneously. Accordingly, a “competing request” for 

purposes of sections 13.2 and 14.2 may also include a transmission service request for 

which transmission capacity cannot be accommodated without preempting one or more 

existing transmission reservations of parts thereof. 

818. In response to TranServ and Duke, we clarify that sections 13.2 and 14.2 allow an 

eligible customer to retain its original reservation by matching the competing service 

request’s cost or duration terms exactly or by exceeding one or more of the terms of a 

competing transmission service request. Since any “match” by an eligible customer in 

response to a potentially preempting request, by definition, either exceeds the costs, 

duration or both of the eligible customer’s original reservation, we do not believe eligible 

customers opting to match a competing request have a strong incentive, if any, to “match” 

a competing request with terms that exceed the competing request. Nevertheless, we do 
Docket No. RM05-17-001, et al. - 433 -

not see any harm resulting from a match that exceeds the exact terms of a competing 

request and therefore believe it would not be appropriate to preclude the ability of eligible 

customers to make such a request. 

819. With regard to reassignments of capacity in the secondary market, we clarify that 

the associated right of first refusal under sections 13.2 and 14.2 of the pro forma OATT to 

match a competing transmission service request applies to the primary transmission 

service, not the reassignment of scheduling rights. Using TranServ’s example, the 

reassignment of one day of a customer’s weekly service would not cause the assignor or 

the assignee to match a competing three day request for service since the initial one week 

reservation already exceeded the competing request. The fact that one day of service has 

been reassigned does not alter the assignor’s entitlement to use service for the remaining 

week reserved. 

820. Finally, we grant rehearing to revise sections 13.2 and 14.2 of the pro forma OATT 

to clarify, as Bonneville requests, the terms and obligations of sections 13.2 and 14.2 of the 

pro forma OATT. 

5. Designation of Network Resources

821. In Order No. 890, the Commission addressed certain issues with respect to the 

qualification, documentation and undesignation of resources by a network customer. A 

number of petitioners request rehearing and clarification of the Commission’s rulings on 

these issues. We address each of these issues in turn. 
Docket No. RM05-17-001, et al. - 434 -

a. Qualification as a Network Resource

(1) LD Contracts

822. In Order No. 890, the Commission affirmed its existing policy that a power 

purchase agreement may be designated as a network resource provided it is not 

interruptible for economic reasons, does not allow the seller to fail to perform under the 

contract for economic reasons, and requires the network customer to pay for the 

purchase. The Commission concluded that power purchases with a firm liquidated 

damages (LD) provision may be eligible for designation as a network resource if the 

contract obligates the supplier, in the case of interruption for reasons other than force 

majeure, to make the aggrieved buyer financially whole by reimbursing them for the 

additional costs, if any, of replacement power. The Commission found that the “make 

whole” LD provisions in the EEI firm LD product and the WSPP Schedule C agreement 

satisfy this requirement.308

Requests for Rehearing and Clarification

823. NCPA contends that the EEI Firm LD Product does not provide recovery for 

certain types of penalties that a buyer may incur as a result of non-delivery and, therefore, 

does not make buyers sufficiently whole to justify designation as a network resource. 

 308 The Commission further concluded that the WSPP Schedule C agreement 

appeared to allow interruptions for reasons other than reliability and, as a result, was 

ineligible for designation as a network resource. The Commission exercised its 

discretion not to invalidate existing designations of the WSPP Schedule C agreement 

except under certain conditions. WSPP subsequently amended the Schedule C agreement 

to expressly prohibit interruptions for reasons other than reliability. See Western 

Systems Power Pool, 119 FERC ¶ 61,123 (2007). 
Docket No. RM05-17-001, et al. - 435 -

NCPA states that Section 1.51 of the EEI Firm LD Product prohibits the reimbursement 

price from including “any penalties, ratcheted demand or similar charges.” NCPA states 

that its contract with the California ISO provides for significant penalties if NCPA 

operates outside of its deviation band, but there is no avenue under the EEI Firm LD 

Product to recover those costs if occasioned by a seller’s failure to deliver. 

824. NCPA also contends that the WSPP Schedule C contract fails to explicitly allow 

buyers to recover their costs if they decide to cover a non-delivery by running their own 

more expensive generation. NCPA states that the issue has been discussed at WSPP 

meetings, but there appears to be no clear consensus that sellers are obligated to pay 

compensation for internal generation under the current language of the agreement when it 

is more expensive than the market cost of power. NCPA argues that this interpretation 

could be particularly problematic for entities such as NCPA, as NCPA may prefer to run 

even very expensive generation to avoid penalties imposed by the California ISO. 

825. NCPA argues that the Commission established a clear and straightforward 

standard that an LD clause was acceptable if it required the buyer to be made whole in 

the event of a failure to deliver. NCPA argues that the Commission can resolve the 

factual issues by directing that these form contracts be amended to require sellers who 

elect not to deliver (other than for force majeure) to make the buyer whole in all respects, 

including contractual or market penalties and the costs of the buyer operating its own 

resources. 

826. Ameren argues that the Commission’s decision that purchase agreements 

containing make whole LD provisions can qualify as network resources ignores 
Docket No. RM05-17-001, et al. - 436 -

reliability. Ameren maintains that the key issue is whether such LD products can 

function as a resource to provide power, not whether the power purchaser will be 

adequately compensated in the event of a breach. Even with a make whole payment 

provision in place, Ameren argues that it may still be in the economic interest of the 

seller to interrupt delivery. While the Commission has appropriately recognized that this 

self-interest warrants finding that other types of LD contracts cannot be designated as 

network resources, Ameren contends that the Commission fails to explain why it should 

not apply the same standard to purchase agreements with make-whole LD provisions. 

827. Ameren also expresses concern that purchase agreements with make whole LD 

provisions may be double-counted when determining capacity, resulting in inadequate 

physical supplies to meet the simultaneous capacity needs of all purchasers in the event 

replacement power is needed. Ameren argues that allowing these types of contracts to 

qualify as network resources is inconsistent with the pro forma OATT because under 

such contracts there are no specific resources that can be called on. Ameren questions 

whether LD products are sufficiently firm to meet the applicable NERC or regional 

reliability council requirements for firm resources or as a capacity resources. 

828. PJM raises a similar concern, asking the Commission to confirm that firm power 

purchase agreements with make whole LD provisions do not qualify as capacity 

resources in the PJM region even if they can be designated as network resources under 

the pro forma OATT. PJM argues that service as a capacity resource in the PJM region 

raises different considerations than those addressed in Order No. 890. 
Docket No. RM05-17-001, et al. - 437 -

829. Noting that parties often modify form agreements to suit their particular 

transactions, Duke requests clarification that a purchase based on the EEI Master 

Agreement qualifies as a designated network resource only to the extent that the network 

customer has, in fact, contracted for a firm resource that may be interrupted only for 

reliability purposes. Duke also requests clarification that an agreement that is not 

modeled after the EEI Master Agreement will qualify as a designated network resource 

only if it provides for delivery of a product similar to the EEI Firm LD Product (i.e., it 

cannot be interrupted for economic reasons). 

830. EPSA requests clarification that the Commission’s statement in Order No. 890 that 

firm LD contracts create for the buyer a contractual right to generation was not intended 

to require that a firm LD contract include a contractual right to the output of a specific 

generating facility. 

831. PNM seeks confirmation that a particular long-term power purchase agreement 

between itself and Southwestern Public Service Company (SPS) is eligible for 

designation as a network resource. While the terms of this agreement allow for a 

specified level of curtailment by SPS each month for any reason, the operating 

procedures governing the agreement provide for curtailment and interruption only for 

system emergencies. PNM argues that this agreement is therefore sufficiently firm to be 

designated as a network resource.309

 309 Citing Consolidated Edison v. Pub. Serv. Elec. & Gas Co., 101 FERC ¶ 61,282 

(2002). 
Docket No. RM05-17-001, et al. - 438 -

Commission Determination

832. The Commission affirms the finding in Order No. 890 that the make whole LD 

provisions in the EEI firm LD product and the WSPP Schedule C agreement are 

sufficiently firm to make those agreements eligible for designation as a network resource. 

In Order No. 890, the Commission distinguished between LD provisions that make the 

aggrieved buyer financially whole by reimbursing the additional costs, if any, of 

replacement power and LD provisions that establish penalties at a fixed-dollar amount, 

cap penalties at some level, or are otherwise not equivalent to a general make whole 

provision.310 The Commission explained that, under the latter type of LD provision, the 

seller need only compare its savings from interruption with the specified LD penalty 

when deciding whether to interrupt. The EEI firm LD product and the WSPP Schedule C 

agreement make the buyer adequately whole and, therefore, appropriately qualify for 

designation as a network resource. 

833. With respect to the EEI firm LD product, section 1.51 of the EEI Master 

Agreement defines the replacement price as either the prevailing market price or, at the 

buyer’s option, the price at which the buyer purchases a replacement product plus costs 

reasonably incurred in purchasing the substitute product and any reasonably incurred 

transmission charges to deliver the product. While the replacement price does not 

exclude penalties, ratcheted demand, or similar charges, as NCPA points out, that does 

not mean a supplier has inadequate incentives to deliver under the contract. The 

 310 See Order No. 890 at P 1453. 
Docket No. RM05-17-001, et al. - 439 -

aggrieved buyer is explicitly allowed to cover the costs reasonably incurred to purchase a 

substitute product and, therefore, the seller must take into consideration the buyer’s actual 

cost of replacement power, which is our principal concern. 

834. With respect to the WSPP Schedule C product, the Commission did not require 

that contracts make the buyer more than whole in the event it chooses not to purchase less 

expensive energy available in the market. Again, the Commission is concerned that 

suppliers providing resources that have been designated by network customers take into 

consideration the cost of replacing that power should the supplier decide to interrupt. It is 

therefore adequate for a firm LD contract, such as the WSPP Schedule C agreement, to 

provide for recovery of the market price of replacement power in the event the buyer 

decides to run its more expensive generation to cover the interruption. 

835. We disagree with Ameren that allowing power purchase agreements containing 

make whole LD provisions to qualify for designation as network resources will 

compromise reliability. Firm energy purchases need not be backed by capacity to qualify 

as network resources since they are by definition firm, consistent with the Commission’s 

finding in Illinois Power.

311 We appreciate Ameren’s concerns that system reliability be 

maintained and would not expect double-counting of supplies to result from our 

designation rules. The proper mechanism for addressing system reliability is through the 

reliability standards, and not through restrictions on eligibility for network resource 

 311 Illinois Power Co., 102 FERC ¶ 61,257 at P 14 (2003), reh’g denied, 108 FERC 

¶ 61,175 (2004) (Illinois Power). 
Docket No. RM05-17-001, et al. - 440 -

status. The requirements for eligibility for network resource status are intended to 

provide the proper incentives to network customers designating network resources, and 

not to replace or replicate reliability requirements. 

836. Our decision is not, as Ameren claims, inconsistent with the structure of the pro 

forma OATT. As the Commission acknowledged in Order No. 890, there may be 

situations in which the supplier of a firm LD product is presented with a net financial 

gain and has an incentive to interrupt, but those incentives are similar to those faced by 

the owner of a generating unit that has been designated as a network resource.312 Ameren 

offers no reasons to require power purchase agreements not tied to a particular generating 

unit to be more firm than those that are in order to serve as a network resource under the 

pro forma OATT. 

837. We clarify in response to Duke that we are not concerned with the particular form 

used to contract for resources. Each power purchase agreement designated as a network 

resource must meet the relevant requirements. Whether a contract meets these 

requirements by being modeled after any specific form contract has no bearing on 

whether the contract is eligible for designation as a network resource. Consistent with 

Illinois Power, a firm LD contract need not represent a contractual right to the output of 

any specific generating facility. Whether or not such power purchase agreements may 

serve as a capacity resource under PJM’s Reliability Pricing Model (RPM) is governed 

by the relevant RPM rules adopted by PJM, which were not addressed in Order No. 890. 

 312 See Order No. 890 at P 1454. 
Docket No. RM05-17-001, et al. - 441 -

838. In response to PNM, we decline here to rule on whether a particular purchase 

qualifies as a network resource because the contract is not before us in this rulemaking. 

We reiterate, however, that power purchase agreements that are not interruptible for 

economic reasons may qualify for designation as a network resource. If the binding rules 

governing a particular agreement allow the seller to curtail or interrupt service only for 

system emergencies, then that agreement would be eligible for designation as a network 

resource, provided it complied with the remaining requirements of section 29.2(v) of the 

pro forma OATT. 

(2) Off-System Resources

839. In order to ensure that transmission providers have sufficient information to 

determine the effect on ATC associated with the designation of an off-system network 

resource, the Commission in Order No. 890 modified section 29.2(v) of the pro forma

OATT to specify exactly what information must be provided to designate an off-system 

network resource. As revised by Order No. 890, section 29.2(v) of the pro forma OATT 

requires the following information to be provided with the request and posted on OASIS 

when designating an off-system resource: (1) identification of the resource as an offsystem resource; (2) amount of power to which the customer has rights; (3) identification 

of the control area from which the power will originate; (4) delivery point(s) to the 

transmission providers’ transmission system; and (5) transmission arrangements on the 

external transmission system(s). Additionally, Order No. 890 revised section 29.2(v) of 

the pro forma OATT to require that the following information be provided with offsystem designations, but that such information must be masked on OASIS to prevent the 
Docket No. RM05-17-001, et al. - 442 -

release of commercially sensitive information including (1) any operating restrictions 

(periods of restricted operation, maintenance schedules, minimum loading level of 

resource, normal operating level of resource); and (2) approximate variable generating 

cost ($/MWH) for redispatch computations. 

Requests for Rehearing and Clarification

840. Duke argues that the Commission’s finding that network customers need only 

identify the control area from which power will originate for an off-system resource is 

inappropriate in an era in which many control areas encompass the transmission systems 

of multiple operating companies. Duke requests rehearing, arguing that the Commission 

should require network customers to provide more specific information for multicompany systems (like Southern) or for ISOs or RTOs. Duke argues that designations 

such as “the Southern system” or “the PJM system” do not provide sufficient granularity 

to accurately model a transaction. Duke maintains that a network customer should at 

least be required to specify the transmission system (e.g., Georgia Power Company for 

Southern, or Dominion Virginia Power Company for PJM) from which the power will 

originate. 

841. Duke acknowledges that the Commission stated in Order No. 890 that 

transmission providers could seek amendments to their OATT via an FPA section 205 

filing if they believe that they face unique circumstances that require deviations from the 

pro forma OATT to require additional granularity in order to allow them to determine the 

effects of designating network resources on ATC. Duke argues that this is an inadequate 

response to the problem, stating that the standard for receiving Commission approval of a 
Docket No. RM05-17-001, et al. - 443 -

variation from the pro forma OATT has proved to be a significant bar. Duke also argues 

that transmission providers could undermine consistency by developing different 

manners in which to study and analyze such designations. Instead, Duke argues, this 

issue ought to be resolved “up front” and on a consistent basis, rather than in subsequent 

case-by-case skirmishes that may not provide guidance for future disagreements. 

842. TDU Systems disagree with Duke in their post-technical conference comments, 

arguing that the requirement to identify the control area within which an off-system 

resource is located provides the appropriate balance. TDU Systems contend that 

identification of the control area allows control area operators to calculate the effects on 

ATC of the designation of an off-system resource while protecting commercially 

sensitive information about the specific location of a customer’s generation resources. 

Southern agrees that (at least in the Eastern Interconnection) requiring the identification 

of the “control area(s)” gives the transmission provider sufficient information to reliably 

plan its system while also providing the market with the flexibility afforded by such offsystem seller’s choice contracts. 

843. Several petitioners request clarification that specification of the control area is not 

required within purchase agreements for generators located off-system.313 These 

 313 E.g., Financial Service Joint Requestors, Idaho Power, Washington IOUs, and 

Morgan Stanley, joined by Barrick Goldstrike Mines in its post-technical conference 

comments. Washington IOUs also argues that the requirement to identify the originating 

control area “constitutes a direct restriction on the ability of a utility to serve its bundled 

retail load, and thus violates the limitations on the Commission’s jurisdiction over 

transmission in bundled retail transaction, citing Northern States Power Co. v. FERC, 

176 F.3d 1090 (8th Cir. 1999) and Order No. 890 at P 92-94. 
Docket No. RM05-17-001, et al. - 444 -

petitioners argue that only the actual delivery point for power (which could be a physical 

resource, a liquid trading hub, and interface point, or some other location) is necessary 

for transmission system modeling purposes. Information about the originating control 

area, they contend, is almost never known with certainty at the time the request for 

designation as a network resource is made and, therefore, requiring such specificity will 

effectively invalidate such contracts as network resources. Financial Service Joint 

Requestors and Idaho Power contend that such a requirement could have serious adverse 

effects on liquidity, competition, and risk management by limiting the ability of 

marketers to participate in those markets, restricting resource options for LSEs. Financial 

Service Joint Requestors maintain that participation in the market by companies like its 

members augments the number of highly creditworthy counterparties willing and able to 

supply power over mid-to-long tenors to LSEs. 

844. In their post-technical conference comments, Financial Service Joint Requestors 

argue that the Final Rule’s acceptance of LD contracts conflicts with the requirement in 

section 29.2(v) to specify the control area(s) from which the power is sourced, since an 

LD contract may not provide that information. Financial Service Joint Requestors also 

argue that Order No. 890 could be interpreted to allow a contract to qualify as a network 

resource by identifying multiple control areas of origin of the resource, although not the 

resource itself. Financial Service Joint Requestors state that there is likely to be a wide 

range of control areas from which power might ultimately be sourced and listing each and 

every possible originating control area (such as listing all 33 control areas in the Western 

Interconnection) seems to be unduly burdensome and cumbersome. 
Docket No. RM05-17-001, et al. - 445 -

845. APS and EEI, and Financial Service Joint Requestors, joined by Southwestern 

Utilities in their post-technical conference comments, argue that transmission providers 

should have discretion to waive the requirement to provide originating control area 

information for proposed network resources when such information is not needed or is 

not meaningful for determining impacts on ATC. APS and EEI state that it uses an 

approved rated path methodology to determine ATC, under which the control area of an 

off-system purchase delivered to one of its liquid trading hub border interfaces (Palo 

Verde or Four Corners) has no effect on ATC calculations. APS and EEI state that this 

contrasts with a flow-based ATC methodology, where the specification of the originating 

control area can affect the ATC on a transmission provider’s system and, therefore, be 

necessary to calculate ATC. APS and EEI argue that requiring the source control area for 

all purchased power network resources will significantly reduce the liquidity of physical 

power markets at Palo Verde and potentially elsewhere in the West. APS and EEI argue 

that concerns about discrimination could be addressed by directing transmission 

providers to post a nondiscriminatory policy on its OASIS or directing NAESB to include 

this issue in its business practices. 

846. APS and EEI, and Southwestern Utilities agree, in their post-technical conference 

comments, that the Eastern and Western Interconnections have very different physical 

configurations, operating modes and planning modes that have implications for the 

Commission’s rules for designating off-system network resources. In the Eastern 

Interconnect, EEI argues, contract paths have little bearing on how electrons actually 

flow, and thus it is critical for transmission planners to know the location, at least at the 
Docket No. RM05-17-001, et al. - 446 -

control area level, of the generation when reviewing requests to designate network 

resources. In the Western Interconnection, which uses a rated path ATC calculation 

methodology, APS and EEI, and Southwestern Utilities argue that identification of the 

source generation for an off-system resource is not important. EEI explains that the 

physical layout in the West is more of a hub-and-spoke model where the only information 

required to evaluate a request to designate a network resource is the point at which power 

is delivered (often a trading hub). For these reasons, EEI argues, seller’s choice contracts 

are not appropriate for network resource status in the Eastern Interconnection, but work 

well in the Western Interconnection. 

847. Pacific Northwest IOUs also agree, in their post-technical conference comments, 

that it is not necessary in the Western Interconnection for a transmission provider to 

know the source control area of a remote resource in order to determine its effect on 

ATC, since WECC path ratings incorporate parallel flows and other operational 

conditions. Pacific Northwest IOUs state that it is only necessary for a transmission 

provider in the WECC to know the border location at which power will be delivered to its 

system in order to determine the effect of the designation on ATC. 

848. Morgan Stanley similarly argues, in its post-technical conference comments, that, 

at a minimum, source control area information for network resources should not be 

required in control areas where participants agree that such information is not needed for 

planning purposes. Morgan Stanley suggests that the Commission should create a default 

approach that explicitly allows designations for off-system network resources to not 

specify the resource location. 
Docket No. RM05-17-001, et al. - 447 -

849. APS and EEI state, in its post-technical conference comments, that the kinds of 

seller’s choice contracts at issue (the WSPP Schedule C contracts) are firm, physical 

contracts that require a seller to deliver power at a specified location. Such contracts, 

APS and EEI argue, are an important resource for most network customers, because they 

are not unit contingent, and so sellers must find alternative sources of power and continue 

to perform even in the event of an outage of a particular generator. These contracts, APS 

and EEI contend, are more dependable than contracts that specify a specific generator or 

control area. 

850. APS and EEI further contend that allowing flexibility of supply when it does not 

adversely affect the transmission provider is critical to maintaining liquid power markets 

in the West. The types of contracts which are at issue, particularly when they are 

executed with banks, allow physical transactions that could not otherwise occur due to 

credit quality issues. If the banks conclude that the regulatory constraints are too limiting 

and choose to move to a financial rather than a physical approach to trading power, an 

important market, that is currently available to APS and their customers, will be 

adversely affected. 

851. MISO and Duke oppose allowing a seller’s choice contract that does not meet all 

of the section 29.2 requirements to qualify as a designated network resource. MISO 

argues that the specification of the origin of supply resources or control area improves 

reliability in a tightly interconnected grid. Duke agrees that, as amended, section 29.2(v) 

appropriately requires identification of the control area(s) from which the power will 

originate. Duke argues, however, that there is a facial conflict between this tariff 
Docket No. RM05-17-001, et al. - 448 -

requirement and the preamble, which indicates that off-system seller’s choice contracts 

may be designated network resources. Duke maintains that, unlike a system sale that 

designated a control area from which the power will originate, a seller’s choice contract 

does not require that power actually originate from the control area designated. 

852. Southern notes, in its post-technical conference comments, that the more 

information that can be provided to the transmission provider, the more accurately it can 

model its system and, in turn, calculate ATC. Thus, Southern requests clarification that 

network customers that have designated such an off-system seller’s choice contract as a 

network resource should provide to the transmission provider as much information as the 

customer has regarding the actual, underlying generating facilities from which the power 

will be sourced. 

853. On rehearing, TDU Systems request clarification that a “delivery point” as 

contemplated by section 29.2(v) of the pro forma OATT includes any point on an 

interface where deliveries are made. TDU Systems argue that it is common in the 

industry to purchase a system product from off-system and deliver that product to any 

interconnection point on the interface between the system where the customer’s native 

load is embedded and the system in which the generation is sourced. TDU Systems 

contend that this is how the term “delivery point” is used throughout the industry 

generally and, in particular, in the NAESB WEQ Glossary Subcommittee’s Preliminary 

Draft Glossary which states that “a delivery point can be a delivery node, an aggregation 

of delivery nodes, an interface or trading hub.” TDU Systems contend that NERC’s 

Glossary of Terms Used in Reliability Standards similarly contemplates that a delivery 
Docket No. RM05-17-001, et al. - 449 -

point may include an interface, defining “Point of Delivery” as “a location...where an 

Interchange Transaction leaves or a Load-Serving Entity receives its energy.” TDU 

Systems further argue that current RTO markets embrace the concept of interfaces as 

delivery points, referring to a statement in section 30.2 of the PJM OATT that “in the 

event that the Network Resource to be designated will use interface capacity” 

contemplates interfaces as delivery points. 

854. Several post-technical conference comments raised questions regarding the need 

to specify a firm transmission path for the upstream delivery of off-system firm LD 

contracts designated as network resources.314 Morgan Stanley argues that sellers of firm 

LD contracts typically hedge the risk of non-delivery by purchasing a portfolio of paths 

and sources for supply. If a non-firm path is available that can enable delivery of power 

used to source a designated network resource, Morgan Stanley contends that the use of 

that path should be an option for the seller. Morgan Stanley maintains that its experience 

has shown that firm transmission is often no more reliable than non-firm transmission 

and is often less reliable. By utilizing more flow options, especially during high-load 

periods, Morgan Stanley argues that existing transmission capacity is better utilized, as 

opposed to forcing users into arbitrary firm paths. 

855. Southwestern Utilities similarly request that network customers only be required 

to specify transmission arrangements on external systems from the point at which power 

is contractually received to the delivery point specified on the transmission provider’s 

 314 E.g., Barrick Goldstrike Mines, Morgan Stanley, and Southwestern Utilities. 
Docket No. RM05-17-001, et al. - 450 -

transmission system, rather than from the source generator or control area. Sellers of 

firm LD contracts, Southwestern Utilities argue, would frequently not be able to provide 

a description of the upstream transmission arrangements on external transmission systems 

at the time the sale to a network customer is made because, just as with control area 

location, sellers are reluctant to limit their options well in advance of delivery. 

856. EPSA argues in post-technical conference comments that the Commission should 

require the identification of neither the control area, nor the point of delivery, for “into” 

firm LD products. To do so would be, in EPSA’s view, inconsistent with allowing firm 

LD contracts to qualify for network resource designation without identification of 

specific physical generation resources. 

857. EPSA contends that, prior to the effectiveness of Order No. 890, LSEs have 

consistently been able to obtain network resource designations for into-Entergy firm LD 

contracts, thereby ensuring that the LSEs could rely on firm network transmission to 

deliver the energy to their specific loads when their suppliers delivered energy into the 

Entergy system. EPSA maintains that, beginning July 13, 2007, requests to designate 

into-Entergy firm LD contracts as network resources, even as daily network transmission, 

have been denied because LSEs have been unable to provide Entergy with the source 

control area and information about transmission arrangements associated with a firm 

transmission reservation that will be used to deliver the firm LD contract. 

858. EPSA explains that LSEs cannot provide this information because, until the 

energy is scheduled, the LSE does not know the source control area and transmission 

information. EPSA maintains that, under the flexible terms of the firm LD contract, 
Docket No. RM05-17-001, et al. - 451 -

however, the seller takes full responsibility for ensuring that the energy will be delivered 

into the specified control area. EPSA states that source and transmission arrangement 

information is provided when energy is scheduled, and scheduling is made possible only 

because appropriate transmission arrangements have been made. If a seller cannot make 

the appropriate transmission arrangements to provide energy into the Entergy system, 

EPSA explains, it will have defaulted on its contract to deliver a firm product into 

Entergy. EPSA argues that, as noted in Order No. 890, the liquidated damages resulting 

from such a default makes the buyer whole providing the basis for the Commission’s 

determination that firm LD contracts can be designated as network resources. 

859. EPSA argues that, at a minimum, the Commission should clarify that network 

customers are not required to provide information as to source control area and 

transmission arrangements except on a day-ahead basis when such information is made 

available through required scheduling and tagging procedures. 

860. On rehearing, Washington IOUs argue that any reliability concerns the 

Commission might have about lack of control area information at the time of designation 

is alleviated by the fact that the tagging information provided with a schedule for a 

designated resource contains all information to ensure reliability. 

Commission Determination

861. The Commission affirms the decision in Order No. 890 to continue to require 

identification of the control area in which an off-system resource is located and the 

delivery point(s) to the transmission provider’s transmission system in order to designate 

the resource as a network resource. Providing both the control area in which the off-
Docket No. RM05-17-001, et al. - 452 -

system resource is located and the delivery point(s) to the transmission provider’s system 

is usually sufficiently specific to allow a transaction to be evaluated for its effects on 

ATC of the local transmission system. As the Commission acknowledged in Order No. 

890, however, some transmission providers might need additional information in order to 

determine the effects of designating off-system resources on ATC and that such 

transmission providers could propose variations to the pro forma OATT in an FPA 

section 205 filing.315 We continue to believe that a generic rulemaking is not the 

appropriate venue to make accommodations for system-specific issues faced by 

transmission providers and, therefore, deny Duke’s request to require more specific 

information regarding the transmission system from which power will originate. 

862. Similarly, we decline to generically relax the designation requirements by 

eliminating the need to identify the source control area for an off-system resource or 

delivery point(s) to the transmission provider’s transmission system. The Commission’s 

policy balances the need to accurately model transactions for ATC and related purposes 

and the flexibility of a seller to source power from a range of generators. We are 

unconvinced that identification of the source control area and delivery point(s) is not 

needed to perform the ATC analysis in every circumstance. We therefore reject requests 

to allow designation of purchased power contracts that provide essentially no advance 

information about the location or delivery of their power sources. Waiting until the 

 315 See Order No. 890 at P 1481. 
Docket No. RM05-17-001, et al. - 453 -

scheduling timeframe for tagging information fails to address the up-front need for 

information in order to accurately model ATC. 

863. Several parties raise arguments relevant to local and regional concerns that merit 

consideration, but a generic rulemaking is not the appropriate venue to address such 

concerns. Transmission providers that believe that their circumstances warrant a 

variation from the designation requirements of the pro forma OATT may make a 

proposal under section 205 of the FPA. We have already approved one such request for 

Puget Sound Energy, Inc., conditioned on that company demonstrating that its tariff 

variation continues to be appropriate after the ATC standardization process is 

complete.316

864. We disagree with Financial Service Joint Intervenors’ contention that there is an 

inconsistency between the requirement in section 29.2(v) of the pro forma OATT that the 

network customer identify the control area from which power is sourced and the finding 

in Order No. 890 that firm LD contracts are eligible for designation as network resources. 

The Commission did not state that every firm LD contract can be designated as a network 

resource, but rather that they are eligible for designation. Such contracts must also 

comport with the other requirements of section 29.2 of the pro forma OATT, including 

identifying the control area from which the power will originate, to actually be designated 

as a network resource. A seller’s choice firm LD contract therefore cannot be designated 

 316 See Puget Sound Energy, Inc., 120 FERC ¶ 61,232 (2007); see also Arizona 

Public Service Company, 121 FERC ¶ 61,246 (2007).. 
Docket No. RM05-17-001, et al. - 454 -

until the source control area is disclosed by the seller.317 The Commission’s discussion 

of particular aspects of firm LD contracts does not mean that remaining requirements of 

section 29.2 no longer apply. 

865. We decline to grant Southern’s request to generically require that network 

customers provide as much information as they have regarding the actual, underlying 

generating facilities from which power will be sourced for an off-system seller’s choice 

contract. We encourage network customers to share such information when they have it, 

and encourage transmission providers to develop business practices to establish 

procedures through which network customers can provide such information, but conclude 

that a formal requirement would be cumbersome to administer and enforce. We believe 

that the existing requirements generally provide sufficient information to evaluate a 

designation request. 

866. Section 29.2(v) of the pro forma OATT requires identification of the “delivery 

point(s) to the transmission provider’s transmission system.” To the extent necessary, we 

clarify that the term “delivery point” does contemplate an interface between the local 

transmission provider’s transmission system and the neighboring transmission system 

from which power is being received. In response to Financial Service Joint Intervenors , 

we clarify that the use of the plural “control area(s)” in the revisions to section 29.2(v) 

adopted in Order No. 890 was inadvertent and amend that language accordingly in this 

 317 See Order No. 890 at P 1481 (requiring identification of source control area, 

rather than more specific transmission system, prior to designation of off-system seller’s 

choice contracts). 
Docket No. RM05-17-001, et al. - 455 -

order. We disagree that a network customer could satisfy the requirements of section 

29.2(v) by identifying multiple control areas, such as all 33 control areas in the Western 

Interconnection, from which a particular transaction could be sourced. 

867. In response to Barrick Goldstrike Mines, Morgan Stanley, and Southwestern 

Utilities, the Commission clarifies that the requirement in section 29.2(v) of the pro 

forma OATT to identify the transmission arrangements on external systems applies to the 

transmission leg from the resource being designated to the transmission provider’s 

transmission system. If an off-system power purchase is sufficiently firm to satisfy the 

designation requirements, then the transmission provider need not be concerned with the 

upstream transmission leg(s) from the generator(s) to the point where the buyer takes title 

of the firm power. Because the contract itself is the resource being designated, and that 

contract is firm in nature, it is not necessary to demonstrate the firmness of the upstream 

transmission in order to designate the contract as a network resource. 

(3) On-System Resources

868. In response to a commenter request, the Commission clarified in Order No. 890 

that a customer may not designate as a network resource a seller’s choice power purchase 

agreement that is sourced by generating units internal to the transmission provider’s 

control area, since evaluating the effect on ATC would be problematic. The Commission 

stated that, if a customer wishes to have a choice of resources that are internal to the 

particular transmission provider’s control area from which to dispatch power, it must 

designate each of the resources as network resources. The Commission did not 
Docket No. RM05-17-001, et al. - 456 -

specifically address on-system system sales (i.e., purchases from a specified generation 

system).318

Requests for Rehearing and Clarification

869. Various concerns were raised in post-technical conference comments regarding a 

possible interpretation of Order No. 890 as prohibiting the designation of on-system 

system sales as network resources.319 Some argue that such an interpretation would be 

inconsistent with statements in the NOPR and Order No. 890 that, when a network 

customer is designating a system purchase as a new network resource, the source 

information required in section 29.2(v) should identify that the resource is a system 

purchase and should identify the control area from which the power will originate.320 

Given this discussion in Order No. 890, TAPS and APPA argue that the deletion of 

language requiring “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” from section 

29.2(v) of the pro forma OATT may have been inadvertent. TAPS and APPA state that 

they are unaware of any party having argued against the eligibility of on-system system 

sales for designation as network resources and that, given the absence of any indication 

 318 The Commission proposed in the NOPR to maintain its current policy of 

allowing network customers to designate resources from system purchases not linked to a 

specific generating unit. See NOPR at P 407. 

319 E.g., Alabama Municipal, Hoosier, and TAPS and APPA. 

320 See NOPR at P 408; Order No. 890 at P 1435. 
Docket No. RM05-17-001, et al. - 457 -

of a problem with these types of contracts, the Commission should not implement such a 

policy. 

870. Alabama Municipal argues in its post-technical conference comments that 

designation of on-system system sales as network resources does not contribute to 

difficulties in computing ATC. Alabama Municipal argues that system sales contracts do 

identify the source of power: the seller’s whole generation fleet. Others argue in posttechnical conference comments that, because system power is what utilities use to supply 

retail load, wholesale system power cannot do any more harm to ATC calculations than 

the utility’s service to its retail customers.321

871. Wisconsin Electric argues that stand-alone transmission providers and RTOs 

should be allowed to have different rules regarding the designation of on-system system 

sales as network resources. Wisconsin Electric contends that within MISO, for example, 

deliverability studies are performed for each resource to assess whether the designated 

capacity is deliverable to the MISO system and that, once that deliverability test has been 

satisfied, another load within MISO is able to designate the same resource as a network 

resource. Wisconsin Electric further states that energy may not actually be delivered 

from a designated resource in a particular hour due to MISO decisions on which units are 

dispatched on an hour-by-hour basis. 

872. Others argue in post-technical conference comments that prohibiting the 

designation of on-system system sales as network resources and requiring the designation 

 321 E.g., Alabama Municipal, Hoosier, NRECA 
Docket No. RM05-17-001, et al. - 458 -

of specific generating capacity would not be comparable to the way the transmission 

provider operates when serving its load.322 Some contend that making system products 

more difficult to use is contrary to the Commission’s policy of encouraging and 

facilitating use of long-term contracts and contrary to the Commission’s obligations 

under section 217(b)(4) of the FPA.323

873. Many of the post-technical conference comments raise concerns regarding the 

burdens that would be imposed on customers if they were forced to re-structure their 

system purchase contracts in order to micromanage the designation of their network 

resources. There is general agreement that customers would be subject to unauthorized 

use penalties and would lose the benefits of purchases from system products if they were 

required to designate particular units within the seller’s system.324 In their view, 

requiring identification of each individual generating station with fixed amounts of 

 322 E.g., Alabama Municipal, Hoosier, TDU Systems, and TAPS and APPA. 

323 E.g., Great Lakes, Hoosier, TDU Systems, and TAPS and APPA. 

324 E.g., Alabama Municipal, Duke, Great Lakes, Hoosier, Kansas Power Pool, 

NRECA, PNGC Power, TAPS and APPA, TDU Systems, and Wisconsin Electric. PPL 

Parties also appear to support allowing on-system system sales to be designated as 

network resources. PPL Parties state that they support allowing designation of on-system 

“seller’s choice” contracts, but their comments about increased reliability and reduced 

costs when service is provided by a “fleet of generators” suggest they are specifically in 

support of allowing designation of on-system system sales, and not necessarily on-system 

seller’s choice contracts. Southern also argues that system sales should be allowed to be 

designated so long as the underlying generating facilities are individually capable of 

receiving firm transmission service during the period of designation. 
Docket No. RM05-17-001, et al. - 459 -

generation and fixed amounts of delivery would be chaotic and overwhelming and would 

diminish reliability. 

874. TDU Systems and TAPS and APPA argue in their post-technical conference 

comments that, if on-system system sales are not allowed to be designated as network 

resources, customers will be motivated to seek off-system system products instead, 

leading to pancaked transmission rates and the loss of local transmission providers as 

possible suppliers. TDU Systems also argue that disallowing on-system system sales to 

be designated as network resources would, in some areas, diminish the ability of the 

wholesale transmission-dependent utility systems that provide virtually the only 

competition in retail electricity markets before Order No. 888 to compete effectively. 

TAPS and APPA state that an alternative would be for the on-system seller to be the 

network customer and take on (or possibly avoid) the headache of designating and 

undesignating resources. TAPS and APPA argue that this would be practical, however, 

only if the network customer desires full-requirements system power and that customers 

seeking to use other resources in combination with the system power (as many 

transmission dependent utilities do) would not have this option. TAPS and APPA also 

point out that customers may own transmission facilities for which, under the 

Commission’s policy, credits are to be provided only where the owner of the transmission 

assets is the network customer itself. TAPS and APPA therefore conclude that a 

transmission dependent utility may have good reason to want to be the network customer, 

rather than allowing the transmission provider to assume that role. 
Docket No. RM05-17-001, et al. - 460 -

875. Great Lakes supports TAPS and APPA’s position in its post-technical conference 

comments, adding that requiring transmission dependent utilities to be full-requirements 

customers of a system power seller would effectively shut out entities that do not 

exclusively utilize full-requirements system power contracts. Great Lakes adds that 

transmission dependent utilities have begun to develop the requisite expertise required to 

allow them to compete more effectively in the wholesale market and should not be 

required to give up those benefits in order to utilize system power contracts. 

876. Several petitioners argue that system sales contracts are not the same as seller’s 

choice contracts.325 These petitioners argue that typically a seller’s choice contract 

involves a situation where, under certain delineated circumstances, a seller that would 

normally sell power to the purchaser from one unit may choose to deliver power from an 

alternate unit. These petitioners argue that the Commission’s ruling in Order No. 890 

regarding the eligibility of seller’s choice contracts does not affect the eligibility of 

system sales. 

877. Duke Energy Carolinas contends in its post-technical conference comments that 

the requirement in section 29.2(v) to provide the delivery point for a resource sourced 

from purchased power could be interpreted to require either an interface delivery point or 

a local load delivery point. For system purchases that are sourced by generators in the 

same control area as the load, Duke Energy Carolinas argues, the only delivery point is 

 325 E.g., NRECA, TDU Systems and Wisconsin Electric. Duke Energy Carolinas 

and Hoosier make similar arguments in their post-technical conference comments. 
Docket No. RM05-17-001, et al. - 461 -

the location of the load. Duke Energy Carolinas states that a network load may have 

more than one load delivery point, but all such points are where some network load is 

located. Duke Energy Carolinas also distinguishes system sales from seller’s choice 

contracts, which it states allow the seller to select on a daily basis the source of the 

physical power. Duke Energy Carolinas contends that system sales do not fit within this 

category of seller’s choice contracts since the source control area is known and there is 

no “choice” as to which units will be used to serve a network customer’s load, given that 

units are dispatched according to economic and reliability dispatch principles. 

878. Duke Energy Carolinas also argues that disallowing on-system system sales would 

be inconsistent with the Commission’s longstanding practice of accepting network 

integration transmission service agreements with designated network resources such as 

“Seller’s Generation System” or “Contract with Seller” with no concern about 

transmission providers calculating ATC. Duke Energy Carolinas further argues that 

disallowing on-system system sales would be inconsistent with allowing at least some 

wholesale customers to be classified as native load customers and permitting the seller to 

serve such native load customers from a choice of all of its network resources. If the 

Commission does not allow on-system system sales to be designated as network 

resources, Duke Energy Carolinas requests clarification of whether a wholesale customer 

that entered into an on-system system purchase contract with a transmission provider 

prior to July 13, 2007 can continue to designate the contract as a network resource. Duke 

Energy Carolinas also requests various other clarifications regarding the designation of 

system sales as network resources. 
Docket No. RM05-17-001, et al. - 462 -

879. TAPS and APPA state that, while the pro forma OATT does not now appear to 

require it, they would not object to a requirement that every network customer, as well as 

the transmission providers and merchant affiliates, seeking to designate on-system system 

sales (or generation fleet) list the generators in the portfolio that stands behind it, 

provided that this not translate to a requirement to assign particular generators or amounts 

to serve the contract. These petitioners argue that the location of the generators, which 

presumably the transmission provider knows anyway, ought to be enough to permit the 

transmission provider to determine whether the system sale can be delivered to the 

customer and, thus, whether the designation of the network resource can be accepted. 

880. Bonneville argues that, because of the interconnected nature of a hydroelectric 

power system, it cannot make power sales from particular generating units and, therefore, 

all of its sales are system sales. Bonneville states that the federal hydroelectric projects in 

the Pacific Northwest are multi-purpose projects and that the operators (the United States 

Corps of Engineers and Bureau of Reclamation) cannot dedicate a given hydroelectric 

project to generate a given amount of power every hour to serve a given contract or for 

any other purpose. Bonneville states that almost 100 of its customers take network 

transmission service and have included Bonneville system purchases of power as network 

resources. Bonneville also notes that, under the Northwest Power Act, it is obligated to 

sell electric power to each Northwest utility to meet the firm power load, to the extent 

that the utility’s firm power load exceeds its resources.326 Bonneville maintains that 

 326 16 U.S.C. 839a(10). 
Docket No. RM05-17-001, et al. - 463 -

nothing in the Northwest Power Act contemplates sales out of, or rates based on, 

individual resources, and that all of Congress’s directives treat federal generation as a 

whole and make no distinction based on the individual resource. Bonneville argues that 

it has addressed the ATC issues that the Commission has identified through its AFC 

methodology. PNGC Power and PPC express support in their post-technical conference 

comments for Bonneville’s general position with respect to the designation of on-system 

system sales from the Bonneville’s hydroelectric system. 

881. Several of the post-technical conference comments address the eligibility of onsystem seller’s choice contracts to be designated as network resources. Southern states 

that it generally opposes allowing on-system seller’s choice contracts to be designated on 

a long-term basis, but acknowledges that such contracts might be designated on a shortterm basis. Southern states that many seller’s choice contracts require the source to be 

named at least on a day-ahead basis. Southern states that it would be acceptable to 

designate such resources on a short-term basis once the delivery source is identified. 

882. Kansas Power Pool, however, argues, in its post-technical conference comments, 

that all seller’s choice contracts should be eligible to serve as network resources. Kansas 

Power Pool argues that it is the supplier, not the customer, of a seller’s choice contract 

that enjoys the flexibility to select resources or to determine which resources will or will 

not be dispatched. 

883. Some post technical conference comments argue that seller’s choice contracts 

from on-system generation located in an unconstrained system or zone (i.e., an area 

within which there are no internal paths for which ATC is calculated) should be eligible 
Docket No. RM05-17-001, et al. - 464 -

for network resource status.327 Conversely, Duke Energy Carolinas and EEI argue that, if 

a system or zone has congestion (i.e., internal ATC paths), then unit designation becomes 

necessary to be able to correctly calculate ATC. South Carolina E&G argues that 

unconstrained transmission systems could become constrained over time, but any 

possible need for the designation of network resources to assist in calculating internal 

ATC will be observable on OASIS. South Carolina E&G argues that a transmission 

provider has no incentive to overstate ATC, so the Commission can be assured that 

designation of network resources is unnecessary if OASIS shows no constraints, and vice 

versa. 

884. Other post technical-conference comments oppose the proposal for unconstrained 

transmission areas, at least as applied to on-system system sales, arguing that the 

proposal appears to be motivated by the incorrect assumption that the Commission in 

Order No. 890 found that both on-system seller’s choice contracts and on-system system 

sales are eligible for designation as network resources.328 With regard to seller’s choice 

contracts, Hoosier and TDU Systems argue that adopting an unconstrained transmission 

area approach would leave those LSEs unfortunate enough to be located on constrained 

systems without the transmission rights they had prior to Order No. 890. Hoosier and 

TDU Systems argue that ATC would not be limited unless the transmission provider has 

 327 E.g., Duke Energy Carolinas, EEI, Pacific Northwest IOUs, South Carolina 

E&G, and Southwestern Utilities. 

328 E.g., TAPS and APPA. 
Docket No. RM05-17-001, et al. - 465 -

failed to expand its system to meet the needs of its network customers, pointing to TLR 

statistics to emphasize concerns regarding particular transmission providers. Hoosier 

contends that restricting seller’s choice contracts to particular areas of the transmission 

provider’s system would assume the existence of constraints on a system to such a degree 

that the long-held rights of network customers to designate their historical resources as 

network resources would be eliminated. Hoosier and TDU Systems believe that the 

Commission’s policy should assume transmission providers have been planning and 

expanding their systems appropriately, putting the burden on the transmission provider 

whose system is so constrained that it cannot evaluate internal ATC to make a filing 

proposing changes to its OATT to accommodate their problems. Acceptance of the 

unconstrained transmission area proposal, they argue, would be inconsistent with the 

Commission’s obligations under FPA sections 217. Hoosier and TDU Systems argue 

that the transmission provider should experience no more difficulty in calculating ATC 

for its network customers than it does to serve its own retail native load. 

Commission Determination

885. In the NOPR, the Commission proposed to continue to allow resources from 

system purchases not linked to a specific generating unit to be designated as network 

resources.329 The Commission did not specifically address on-system system sales in 

Order No. 890, focusing instead on on-system seller’s choice contracts.330 Thus, the 

 329 See NOPR at P 407. 

330 See Order No. 890 at P 1483. 
Docket No. RM05-17-001, et al. - 466 -

Commission’s existing policies regarding the eligibility of on-system system sales for 

network resource status were not affected by the reforms adopted in Order No. 890. 

886. Various concerns have nonetheless been expressed regarding the treatment of onsystem system sales in requests for rehearing and clarification and at the technical 

conference held by Commission staff on July 30, 2007 and in subsequent comments. 

TAPS and APPA, for example, question whether the revisions to section 29.2(v) of the 

pro forma OATT adopted in Order No. 890 were intended to alter the designation 

requirements for on-system system sales. Alabama Municipal and Wisconsin Electric 

argue that the Commission’s concerns regarding the accuracy of ATC calculations are not 

relevant in the context of system sales. In order to respond to these concerns, and provide 

guidance to the industry, we clarify that Order No. 890 was not intended to change the 

requirements for designating on-system system sales as network resources under the pro 

forma OATT.331 

887. Prior to Order No. 890, section 29.2(v) of the pro forma OATT did not distinguish 

between the designation of on-system and off-system resources. In order to designate a 

network resource, the network customer was required to provide information regarding 

the unit size, the amount of capacity being designated, VAR capability, operating 

restrictions, approximate variable cost, and arrangements governing the third-party sales 

and deliveries. For off-system power purchases, information was also required regarding 

 331 Slice-of-system sales are a type of system sale and, therefore, our discussion 

below regarding on-system system sales applies equally to on-system slice-of-system 

sales, as well as system sales from hydroelectric systems. 
Docket No. RM05-17-001, et al. - 467 -

the source of supply, control area location, transmission arrangements, and delivery 

point(s) to the transmission provider’s system. These various requirements were stated in 

a single series of bullets in section 29.2(v). 

888. In Order No. 890, the Commission restructured section 29.2(v) to more clearly 

identify the information that must be provided for on-system resources and off-system 

resources, breaking apart the series of bullets into two separate lists. The basic 

requirements of designation remain the same, except that the tariff language more clearly 

specifies the information (i.e., source of supply, control area location, transmission 

arrangements, and delivery point(s) to the system) that applies only to off-system 

resources. This was implicit in the prior tariff formulation, since the underlying 

information related to off-system transactions. The Commission sought to more 

explicitly state the information required under section 29.2(v) to facilitate compliance 

with the new obligation for customers to provide an attestation that the requirements for 

designation as a network resource have been met for the particular resource being 

designated. 

889. These changes to the pro forma OATT therefore did not change the substantive 

requirements for designating network resources as they apply to on-system and offsystem resources. For on-system resources, network customers must continue to provide 

the same information in their designation request: the unit size, the amount of capacity 

being designated, VAR capability, operating restrictions, approximate variable cost, and 

arrangements governing the third party sales and deliveries. We understand that it is 

common practice in the industry for transmission providers to consider the identification 
Docket No. RM05-17-001, et al. - 468 -

of the source system for an on-system system sale sufficient to provide this information, 

since the transmission provider already has the necessary information for constituent 

generators on the system given that the units supporting the system sale have otherwise 

been designated for use by network or native load.332 Nothing in Order No. 890 imposed 

new information requirements on transmission providers that previously deemed the 

requirements of section 29.2(v) fulfilled by the identification of the source system for an 

on-system system sale. Network customers may therefore continue to designate such 

resources as appropriate. 

890. To the extent there are concerns regarding the effect of designating on-system 

system sales on ATC, we note that transmission providers have been directed to address 

the effect on ATC of designating and undesignating network resources as part of the ongoing NERC/NAESB standardization effort.333 Through that process, transmission 

providers will develop consistent methodologies for calculating the effect on ATC of 

designation resources, both on-system and off-system. Until the standardization process 

is complete, however, the Commission cannot know whether additional information is 

required in order to accurately model the designation of an on-system system sale. We 

will revisit the requirements of section 29.2(v) as necessary after the NERC/NAESB 

 332 It may be the case that identification of another system within the transmission 

provider’s control area, such as a fleet of merchant generators, would trigger the need for 

additional information under section 29.2(v). That type of transaction, however, does not 

appear to be of concern to petitioners and thus we do not address it here. 

333 See Order No. 693 at P 1041. 
Docket No. RM05-17-001, et al. - 469 -

ATC standardization effort is complete. Until such time as those requirements change, 

transmission providers should continue their existing practices regarding the designation 

of on-system system sales as network resources. Further clarification as requested by 

Duke is not necessary. 

891. The Commission affirms the finding in Order No. 890 that on-system seller’s 

choice contracts generally do not provide enough information to satisfy the requirements 

for designation as a network resource. For on-system resources, the location of the 

capacity is necessary for determining the effect of a proposed designation on transmission 

capacity, both for evaluating the acceptability of the resource itself, and for allowing 

future transmission service requests to be evaluated. We agree with Southern, however, 

that a contract that may not provide enough information provided to be designated as a 

network resource at one time may become eligible for designation as the information 

becomes available. For instance, if a day before scheduling the seller were to identify 

source generation for a seller’s choice contract for the following day, and if the contract 

were to bind the seller to use the newly identified generation (at least for the period that it 

was identified), then the resource would be eligible to be designated for the period during 

which the source information is firm (provided the resource complied with all other 

relevant requirements). At that point, the agreement is effectively no longer a seller’s 

choice contract for the specified period. If, on the other hand, the seller identifies only 

what it intends to source the power with, but no contractual mechanism prevents the 

seller from sourcing the power from an alternative source prior to scheduling, then the 
Docket No. RM05-17-001, et al. - 470 -

resource would remain a seller’s choice contract and would not be eligible for network 

resource status. 

892. We disagree with Kansas Power Pool’s argument that, because it is not the 

customer that has the flexibility to select the generation in a seller’s choice contract, such 

contracts should be eligible for network resource status. It is the inability to evaluate or 

determine the proper transmission reservations for on-system seller’s choice contracts 

that is concerning, and not the fact that it is the seller or the buyer who has the “choice” 

of how to dispatch the power. 

893. With regard to the proposal to allow the designation of on-system seller's choice 

contracts within unconstrained transmission areas, we believe that our clarification above 

that Order No. 890 did not change the Order No. 888 requirements for designating onsystem system sales will alleviate most of the concerns expressed by supporters of this 

proposal. 

(4) Resource Information

894. In Order No. 890, the Commission affirmed the requirement that customers 

designating a network resource must provide a description of the resource (current and 

10-year projection) including, among other things, approximate variable generating cost 

($/MWH) for redispatch computations and any operating restrictions. 

Requests for Clarification and/or Rehearing

895. EEI requests clarification that the operating restrictions information required by 

section 29.2(v) of the pro forma OATT need not be provided for off-system system sales 

if that information is not contained in the relevant contracts. EEI also suggests that the 
Docket No. RM05-17-001, et al. - 471 -

variable price of energy specified in the contract and not the actual variable costs of the 

units that supply the sale serve as the variable generating cost for redispatch 

computations. EEI argues that the network customer generally will not know the actual 

variable cost and that the price specified in the contract is the relevant price for purposes 

of redispatch, since that is the cost that the network customer will incur or avoid if its 

contract is redispatched up or down. Bonneville and Duke Energy Carolinas question in 

their post-technical conference comments what variable costs should be provided for onsystem system sales. Duke Energy Carolinas states that the contract energy price is used 

as the approximate variable generating cost for redispatch purposes. 

896. EPSA requests clarification that network customers are not required to provide a 

redispatch cost for a firm LD contract, since such contracts are effectively take-or-pay 

contracts and cannot, for example, provide a source of incremental energy if Entergy is 

surveying redispatch options to address a reliability event. EPSA argues that the fact that 

not all network resources are suitable for redispatch options is not unusual, since many 

units may be must-run in order to meet reliability needs (such as voltage support) or 

contractual requirements (such as QF purchases), or to reflect operating characteristics 

(such as nuclear units that cannot be cycled off and on quickly). EPSA is concerned that 

some transmission providers may believe that the supplier of a firm LD contract is 

required to provide the network customer with a contract-specific variable redispatch cost 

based on its own supply alternatives which, as noted, is not possible. EPSA argues that a 

determination that designation requests could be rejected for lack of information that is 
Docket No. RM05-17-001, et al. - 472 -

not relevant to such contracts would be contrary to the Commission determination that 

firm LD contracts can serve as network resources. 

Commission Determination

897. The Commission clarifies in response to EEI that the operating restrictions 

applicable to off-system system sales designated as network resources are the restrictions 

set forth in the relevant contracts, not the underlying units supplying the contracts. 

Similarly, the approximate generating cost for redispatch purposes for a system sale is the 

variable energy cost specified in the contract. 

898. We disagree with EPSA that a network customer should not be required to provide 

a redispatch cost for a firm LD contract. When a network customer designates a network 

resource, it agrees under section 30.5 of the pro forma OATT to redispatch its resource as 

requested by the transmission provider pursuant to section 33.2 of the pro forma OATT. 

A firm LD contract is like any other resource, redispatchable by the transmission provider 

within the customer’s rights to the resource, as stated in the contract. 

(5) General

899. In Order No. 890, the Commission determined that firm point-to-point service 

provided on a conditional firm basis is sufficiently firm to be used for transmission to 

import an off-system designated network resource. The Commission also denied a 

request to require the validity of network resource designations to be verified by the seller 

or owner of the generation, finding that such a verification is unnecessary in light of the 

new attestation requirements. Finally, the Commission clarified that the minimum term 

for designations of new network resources should be the same as the minimum term used 
Docket No. RM05-17-001, et al. - 473 -

for firm point-to-point service (i.e., daily), unless otherwise demonstrated by the 

transmission provider and approved by the Commission. 

Requests for Rehearing and Clarification

900. Duke seeks clarification that network customers that designate off-system 

resources supported by conditional firm point-to-point transmission service are required 

to have in place or obtain from the transmission provider reserves or backup resources to 

cover the periods when the conditional firm point-to-point transmission service is not 

available. 

901. Indicated Commenters argue that a network customer designating a generating 

unit that it does not own should have an obligation to provide contemporaneous notice of 

the designation to the owner of the generating unit. Indicated Commenters argue that 

such notice should indicate, at a minimum, the amount of capacity claimed to be under 

contract and the duration of the claimed contractual right. Indicated Commenters argue 

that their proposed notice requirement is appropriate since designation as a network 

resource may subject the generation owner to certain must-offer requirements (in 

organized markets) or redispatch orders (in non-organized markets). Indicated 

Commenters also contend that such a notice requirement would facilitate enforcement of 

the OATT requirements by ensuring that generators are not obligated without their 

knowledge and that false or questionable designations are identified promptly. Indicated 

Commenters argue that the current system of audits and increased penalty authority and 

other sanctions will have some deterrent effect, but that it will do nothing to make 
Docket No. RM05-17-001, et al. - 474 -

generation owners and other users of the transmission system whole after violations 

occur. 

902. Pacific Northwest Parties, joined by PPC in its post-technical conference 

comments, requests clarification that, to the extent a transmission provider establishes a 

minimum term for designation of network resources, it need not be the same as the 

minimum term offered by the transmission provider for firm point-to-point service. 

Pacific Northwest Parties argue that this clarification will promote hourly firm energy 

markets by allowing transmission providers to offer hourly firm point-to-point 

transmission service even if they cannot accommodate a one-hour minimum term for 

designation of network resources. 

903. Reliant asks in its post-technical conference comments that the Commission 

carefully consider any variations from the network service requirements of the pro forma

OATT proposed by RTOs and ISOs in their compliance filings. Reliant contends that 

requirement for proper identification of network resources is intended to ensure that 

transmission reserved for firm network use is used only to deliver properly designated 

network resources and that no more than one LSE has identified the same resource 

capacity as serving its load (i.e., to avoid double-counting). Reliant asks the Commission 

to ensure that any variations from the pro forma OATT proposed by RTOs and ISOs 

similarly prevent double-counting. 

Commission Determination

904. The Commission declines Duke’s request to require that a network customer, as a 

condition of designating off-system resources supported with conditional firm point-to-
Docket No. RM05-17-001, et al. - 475 -

point transmission service, have in place or obtain from the transmission provider 

reserves or backup resources to cover the periods when the resource supported with 

conditional firm point-to-point transmission service might not be delivered. Duke 

appears to misunderstand the nature of conditional firm service. A network customer 

utilizing conditional firm service would be using firm transmission service except during 

the limited periods where such service is conditional. Transmission service for those 

resources could be curtailed during such periods, similar to how secondary network 

service may be curtailed prior to curtailment of other firm transactions. In the event 

conditional firm service is curtailed, the network customer would be required to serve its 

network load from other resources, just as when the transmission provider curtails the 

network customer’s use of secondary network service. It is not the responsibility of the 

transmission provider to ensure that the network customer has sufficient resources to 

meet its load. 

905. We disagree with Indicated Commenters that network customers should be 

required to serve notice on sellers of power that is designated as a network resource. The 

obligation to comply with the designation requirements applies to the network customer, 

not the resource owner. The appropriate place to impose obligations on the resource 

owner is in the contract governing the sale. To the extent a contract has been executed 

that meets the requirements for network resource designation, it is not clear why the 

seller would be affected by the actual designation of the resource, since the network 

resource redispatch obligations do not go beyond the amount of power that is available 

under the contract as designated by the network customer. If, as Indicated Commenters 
Docket No. RM05-17-001, et al. - 476 -

argue, there are unique considerations in some organized markets, a generic rulemaking 

is not the appropriate venue to make accommodations for such system-specific issues. 

906. We also decline to grant the request of Pacific Northwest Parties to generically 

allow transmission providers to establish a minimum term for designations of network 

resources that is not the same as the term for firm point-to-point service. Pacific 

Northwest Parties do not explain why a transmission provider could accommodate hourly 

point-to-point transmission service, but not hourly network service. To the extent that a 

transmission provider has specific circumstances that justify adoption of a different 

minimum term for network resource designations, it should raise them in the context of 

an FPA section 205 filing. 

907. To the extent Reliant or any other party has a concern regarding an RTO or ISO’s 

compliance with the requirements of Order No. 890, the appropriate forum to consider 

those concerns is on review of the underlying compliance filing. 

b. Documentation for Network Resources

908. The Commission concluded in Order No. 890 that transmission providers should 

be responsible for verifying that third-party transmission arrangements to deliver an offsystem designated network resource to the transmission provider’s system are firm. 

However, the Commission found that transmission providers should not be responsible 

for verifying that the generating units and power purchase agreements designated as 

network resources satisfy the requirements of section 30.1 and 30.7 of the pro forma

OATT. The Commission instead required network customers and the transmission 

provider’s network function to include a statement with each application for network 
Docket No. RM05-17-001, et al. - 477 -

service or to designate a new network resource that attests, for each network resource 

identified, that (1) the transmission customer owns or has committed to purchase the 

designated network resource and (2) the designated network resource comports with the 

requirements for designated network resources. 

909. The Commission stated that network customers should include this attestation in 

the customer’s comments section of the request when it confirms the request on OASIS. 

In the event that a transmission provider or any other network customer designates a 

network resource that it does not own or has not committed to purchase, or that does not 

comport with the requirements for designated network resources, the Commission will 

deem the network customer to be in violation of the pro forma OATT and will consider 

assessing civil penalties on a case-by-case basis, consistent with the Commission’s Policy 

Statement on Enforcement. The Commission rejected requests to allow transmission 

providers to voluntarily verify terms and conditions of power purchase agreements, 

concluding that such authority is unnecessary in light of the new attestation requirement. 

Requests for Rehearing and Clarification 

910. South Carolina E&G asks for clarification of the language describing the 

attestation requirement in paragraph 1521 of Order No. 890, arguing that it is a less 

precise paraphrase of the language in section 30.2 of the pro forma OATT. South 

Carolina E&G asks the Commission to confirm that the precise language of section 30.2 

governs and that paragraph 1521 of Order No. 890 does not add any additional 

requirements. South Carolina E&G also suggests that, because of space limitations in the 
Docket No. RM05-17-001, et al. - 478 -

customer’s comment section on OASIS, the attestation can be made by a reference, such 

as “the customer attests pursuant to Section 30.2.” 

911. Several petitioners request rehearing of the Commission’s decision to not allow 

transmission providers to review power supply contracts for power purchases designated 

as network resources.334 These petitioners argue that allowing such review would 

improve reliability and/or allow transmission providers to more accurately model their 

systems. Duke and EEI argue that transmission providers should have the right, but not 

the obligation, to review such contracts. They assert that transmission providers have a 

legitimate interest in ensuring the reliability of energy service to network loads on their 

systems, since interruptions and resulting imbalances may harm the reliability of the 

entire system, and because the transmission providers may be forced to provide backup 

energy in order to avoid curtailment of network load. EEI complains that network 

customers who incorrectly designate unqualified resources take transmission capacity 

that otherwise would be used for transmission service from legitimate network resources. 

Duke notes that it has routinely been provided access upon request to underlying 

contracts, with commercially sensitive information redacted. 

912. EEI argues that reliance on attestations by network customers that their power 

purchases qualify as network resources is insufficient to adequately protect against 

improper designations. EEI states that some of its transmission provider members have 

found, by comparing customer contracts against network resource certifications that are 

 334 E.g., Duke, EEI, and MISO. 
Docket No. RM05-17-001, et al. - 479 -

required by their business practices, that some customers are incorrectly designating 

power purchase contracts that clearly do not meet the Commission’s criteria. EEI argues 

that after-the-fact audits of customers’ attestations do not address the system reliability 

concerns of the misuse of the transmission system that results from the designation of 

unqualified network resources. 

913. EEI acknowledges the Commission’s reluctance to place transmission providers in 

the position of policing whether customers’ contracts qualify as network resources, but 

argues that does not warrant precluding voluntary review of network customers’ 

purchased power contracts. EEI contends that the Standards of Conduct prohibit any 

transfer of customer information to the transmission provider’s marketing and energy 

affiliates and that any residual concerns about transmission providers deciding whether 

power purchase contracts qualify as network resources could be addressed by permitting 

the transmission provider to act in a purely advisory role. EEI suggests that transmission 

providers could bring concerns about possibly incorrect attestations to the attention of the 

customer or, if necessary, the Commission’s Enforcement Hotline. EEI argues that 

allowing such review by the transmission provider would not supplant the obligation of 

the network customer to attest to the validity of its designations of network resources. 

914. MISO argues that a statement that the transmission customer owns or has 

committed to purchase the designated network resource and that the designated network 

resource comports with applicable requirements does not provide the necessary level of 

assurance to the transmission provider, particularly in those cases where the network 

customer unduly relies on representations made by its supplying marketers. MISO asks 
Docket No. RM05-17-001, et al. - 480 -

the Commission to supplement its existing attestation requirements with a certification 

from an external control area’s administrator and/or the seller of the generation that the 

resource being designated in that area is not counted as a designated network resource for 

another load on or off the system. 

915. Joined by Southern, EEI also objects to making transmission providers responsible 

for verifying the firmness of off-system transmission service. Southern argues that the 

requirement that transmission providers verify the firmness of off-system transmission 

service is unduly burdensome and could result in unnecessary rejection of requests to 

designate network resources on a day-ahead basis. Southern contends that the specific 

transmission path(s) and arrangements to deliver power to the network customer usually 

have not been finalized at the time off-system resources are designated in the “dayahead” cycle and, instead, are typically finalized the hour before delivery. Southern and 

EEI suggest that sections 29.2(viii), 30.1, 30.2, and 30.7 of the pro forma OATT be 

amended to allow the network customer to attest that the external resource is 

contractually required to be delivered using firm transmission service, without 

confirmation that an actual firm path has been scheduled and confirmed. Southern argues 

that transmission customers also could be required to attest to the firmness of their 

requested and expected transmission service and face the possibility of complaint, audit 

or other inquiry and, ultimately, sanction for false attestations. 

916. In the alternative, EEI requests further clarification that transmission providers 

could obtain waiver of the verification requirement if they demonstrate that verification 

of the firmness of transmission service is not required because of the way in which 
Docket No. RM05-17-001, et al. - 481 -

transmission service and markets operate on the transmission provider’s transmission 

system. EEI states that network resources in the West are frequently designated at hubs 

such as the Palo Verde Hub prior to tagging. EEI states that a network customer has very 

limited ability to know the source of the energy that is being made available at a specific 

hub and, indeed, has no need to know that information since what is important is the 

seller’s commitment that the energy is being provided at that hub on a firm basis. EEI 

argues that the host transmission provider has no ability or need to evaluate the firmness 

of the external transmission path between the generator and hub. EEI contends that the 

Commission’s decision to require verification of the firmness of transmission paths, in 

conjunction with other requirements relating to off-system network resources, has caused 

financial institutions to consider withdrawing from the market. 

917. EEI and Southern also argue that, in many instances, transmission providers are 

unable to perform the verifications required by the Commission. They state that some 

systems refuse to allow other transmission providers access to their OASIS and refuse to 

perform the verification themselves. EEI suggests that the Commission require each 

transmission provider to grant “read only” access to its OASIS by any computer that has 

an X509 security certificate (the security certificate that is provided to transmission 

function personnel). EEI requests that the Commission, at a minimum, delay the date by 

which transmission providers must verify off-system transmission service for 180 days, 

in order to allow time for modifications to OASIS protocols to grant access to 

transmission providers who are seeking to verify the firmness of transmission service. 
Docket No. RM05-17-001, et al. - 482 -

918. If the Commission declines to amend the attestation requirement, EEI requests 

clarification with regard to instances where transmission providers cannot verify the 

firmness of off-system transmission service because the information is not posted on 

OASIS. EEI states that many non-jurisdictional transmission providers that do not have 

reciprocity tariffs also do not have OASIS nodes on which the firmness of service can be 

verified. EEI also states that grandfathered transmission agreements frequently are not 

posted on OASIS or, if they are posted, postings do not contain sufficient detail to enable 

off-system transmission personnel to verify the firmness of the transmission service. 

Commission Determination

919. The Commission clarifies, in response to South Carolina E&G’s request, that the 

language in paragraph 1521 of Order No. 890 is only meant to be a paraphrase of the 

more detailed attestation to be provided in the pro forma OATT itself. A network 

customer designating network resources should submit an attestation using the language 

set forth in sections 29.2(viii) and 30.2 of the pro forma OATT, as amended in Order No. 

890, not the language of the preamble. A network customer is not permitted to merely 

reference the applicable section of the pro forma OATT when completing the attestation 

requirement. If the OASIS customer comment section does not currently allow enough 

space for a network customer to provide its attestation, transmission providers should 

modify, in coordination with NAESB, OASIS functionality to accommodate the full 

attestation. In the interim, the transmission provider should identify alternate means, 

such as by telefax or e-mail, for the network customer to provide the attestation. 
Docket No. RM05-17-001, et al. - 483 -

920. We decline to require that network customers provide their power supply contracts 

to transmission providers for review, whether such review is advisory or otherwise. 

Allowing transmission providers to review power sales contracts would put transmission 

providers in the position of interpreting their network customer’s contracts and accepting 

or rejecting designations based on their interpretations. Regardless of the protections 

provided by the Standards of Conduct, it would be inappropriate for transmission 

providers to be in that position. The new attestation requirement properly places the 

responsibility of interpreting the terms of a power sales agreement on the network 

customer, an actual party to the agreement. We believe that the new attestation 

requirement, coupled with the prospect of significant civil penalties for improper 

attestations, will prove effective at providing the proper incentives for network customers 

to not designate ineligible network resources. 

921. Similarly, we decline to require, as requested by MISO, that network customers 

designating off-system resources provide a certification from the external control area’s 

administrator and/or the seller of the generation that the resource being designated is not 

counted as a network resource for another load. Again, it is the responsibility of the 

network customer to assure that the requirements of the pro forma OATT are satisfied 

prior to requesting the designation of a network resource. The network customer must 

take appropriate steps to ensure that the resource has not been committed for sale to nondesignated third party load or is otherwise unable to be called upon to meet the network 

customer’s network load on a non-interruptible basis. 
Docket No. RM05-17-001, et al. - 484 -

922. We affirm the decision in Order No. 890 to require each transmission provider to 

verify the firmness of off-system transmission service to deliver designated network 

resources to the transmission provider’s system. Under normal circumstances, this 

verification requirement should not present a significant burden for the transmission 

provider because it only requires review of the transmission arrangements from the 

designated network resource to the transmission provider’s system. Several of the 

arguments raised by petitioners incorrectly assume that the transmission provider is under 

an obligation to look beyond a power purchase designated as a network resource to 

upstream transmission arrangements from the source generator. There is no need for the 

transmission provider to consider transmission arrangements upstream of the designated 

resource, since the network customer has attested that the resource is sufficiently firm to 

be designated as a network resource. We therefore do not believe, as Southern argues, 

that the verification process will result in unnecessary rejections of request to designate 

network resources. 

923. We recognize that, in some circumstances, the external transmission provider may 

not have an OASIS or make relevant information on its OASIS available to other 

transmission providers and, therefore, the host transmission provider may be unable to 

use OASIS to verify the firmness of transmission used to deliver the off-system 

designated network resource. The Commission explained in Order No. 890 that the 

transmission provider should attempt to remedy such information deficiencies through 
Docket No. RM05-17-001, et al. - 485 -

informal communications with the customer.335 Network customers have every incentive 

to cooperate in providing this information since, if the transmission provider is unable to 

confirm the firmness of these transmission arrangements, the request to designate the 

network resource is deficient. We agree with EEI and Southern, however, that 

transmission providers should have access to view other transmission providers’ OASIS 

for this purpose. We therefore direct transmission providers to allow such access and to 

work through NAESB to modify business practices as necessary.336 We decline to waive 

the verification requirement in the interim since transmission providers are able to request 

this information directly from customers. 

c. Undesignation of Network Resources

(1) Risk to ATC Rights

924. The Commission clarified in Order No. 890 that a request for termination of a 

network resource that is concurrently paired with a request to redesignate that resource at 

a specific point in time will not result in the network customer permanently forfeiting its 

rights to use that resource as a designated network resource. Any change in ATC that is 

determined by the transmission provider to have resulted from the temporary termination 

shall be posted on OASIS during this temporary period. A request that is not 

 335 See Order No. 890 at P 1527. 

336 Transmission providers are free to use the NAESB standards development 

process to create automated OASIS functionality for verifying third-party transmission 

service at the time a designation request is submitted or any other processes to further 

minimize any burden associated with the verification requirement. 
Docket No. RM05-17-001, et al. - 486 -

accompanied with a request to redesignate that resource at a specific point in time is to be 

considered an indefinite termination. After an indefinite termination of a resource, the 

network customer has no continuing rights to the use of such resource and future requests 

to designate that resource would be processed consistent with section 30.2 of the pro 

forma OATT as a designation of a new network resource. 

Requests for Clarification and Rehearing

925. NorthWestern argues that, once upgrades specified through the interconnection 

process have been installed, the generator can be specified as a network resource by any 

customer, at the time of commercial operation of the generator or at any time in the 

future. NorthWestern acknowledges that the Commission rejected this position in Order 

No. 890, but contends that the Commission’s determination cannot be reconciled with the 

ability of a generator under Order No. 2003 to designate, during the application process, 

whether it wishes to be studied and interconnected as a network resource or an energy 

resource.337 NorthWestern contends that interconnection as a network resource assumes 

that the generator will be eligible to be designated by any network customer to serve its 

load in the future. If this is not the case, NorthWestern questions the distinction between 

energy resource interconnection service and network resource interconnection service 

and the transmission provider’s ability to confidently study any network generation 

request will be diminished. NorthWestern states that a generator’s request for network 

interconnection does not necessarily mean that any customer has designated the generator 

 337 Citing Order No. 2003. 
Docket No. RM05-17-001, et al. - 487 -

as a network resource, but only that it may be designated as a network resource by any 

customer. 

926. NorthWestern also requests clarification regarding the interaction of transmission 

service and generation interconnection requests, asking the Commission to confirm that 

both should be studied through a single queue prioritized by request date. NorthWestern 

argues that decoupling the network generation interconnection study from the 

transmission service study could undermine reliability. NorthWestern suggests that all 

generation interconnection and transmission service requests be studied through a single 

study queue, where the requests are prioritized by their request date, in order to allow the 

relationship and mitigation requirements between senior and junior queued transmission 

and interconnection requests to be known and applied appropriately in junior queue 

studies. 

Commission Determination

927. We disagree with NorthWestern that a generator interconnected under network 

resource interconnection service (NRIS) may be designated as a network resource by any 

customer at any point in time. As the Commission explained in Order No. 2003-A, NRIS 

status does not convey any right to transmit power and does not constitute a reservation 

of transmission capacity to any specific point.338 The purpose of NRIS is to provide only 

those network upgrades needed to allow the aggregate of generation in the facility’s local 

area to be delivered to the aggregate of load on the transmission provider’s transmission 

 338 Order No. 2003-A at P 516. 
Docket No. RM05-17-001, et al. - 488 -

system, such that the output of the generating facility will not be “bottled up” during peak 

load conditions.339 As a result, NRIS does not necessarily provide the interconnection 

customer with the capability to physically deliver the output of its generating facility to 

any particular load on the system without incurring congestion costs. Requests for 

delivery service inside the transmission provider’s transmission system may require 

additional studies and upgrades to reduce congestion to acceptable levels.340

928. We decline to adopt at this time NorthWestern’s request that all transmission 

service and generation interconnection requests be studied through a single queue 

prioritized by application date and time. NorthWestern requests specific revisions to the 

management of generator interconnection and transmission service request queues that 

were not proposed in the NOPR and are beyond the scope of this proceeding. Earlier this 

month, Commission staff held a technical conference to address issues related to the 

management of interconnection queues in Docket No. AD08-2-000.341 The queuing 

concerns raised by NorthWestern are more appropriately addressed in that proceeding. 

(2) Minimum Lead-Time

929. The Commission concluded in Order No. 890 that network customers should not 

be permitted to make firm third-party sales from any designated network resource 

 339 Id. at P 531. 

340 Id. at P 502. 

341 See Interconnection Queuing Practices, Notice of Technical Conference, 

Docket No. AD08-2-000 (Nov. 2, 2007); Interconnection Queuing Practices, Notice 

Inviting Comments, Docket Nos. AD08-2-000, et al.
Docket No. RM05-17-001, et al. - 489 -

without (1) undesignating that resource for the period of the third-party sale pursuant to 

section 30.3 of the pro forma OATT and (2) providing notice of such undesignation 

before the firm scheduling deadline. The Commission stated that this requirement allows 

undesignated capacity to be acquired on a non-firm basis without creating an undue 

adverse effect on third-party sales. 

Requests for Clarification and Rehearing

930. Various petitioners have requested rehearing or clarification of the Commission’s 

determinations regarding the minimum lead-time for undesignating network resources in 

order to make firm third-party sales.342 Petitioners generally object to imposing this 

minimum lead-time requirement, arguing that it unduly restricts the ability of network 

customers and the transmission provider to engage in third-party sales and impairs 

liquidity in the market. 

Commission Determination

931. In a notice issued on September 7, 2007, the Commission extended the effective 

date of the minimum lead-time for undesignating network resources adopted in Order No. 

890, deferring the effectiveness of the phrase “... but not later than the firm scheduling 

 342 E.g., APS and EEI, E.ON U.S., Financial Service Joint Filers, Pacific 

Northwest Parties, PNM, Progress Energy, Washington IOUs, and WSPP. In addition, 

APS and EEI, Barrick Goldstrike Mines, Bonneville, EPSA, Morgan Stanley, Pacific 

Northwest IOUs, PNGC Power, Powerex, PPL Parties, Public Power Council, San Diego 

G&E, SCE&G, SoCal Edison, Southern, Southwestern Utilities, and WSPP filed posttechnical conference comments on this issue. 
Docket No. RM05-17-001, et al. - 490 -

deadline for the period of termination” in section 30.3 of the pro forma OATT.343 The 

Commission stated that it will address the appropriate effective date for that tariff 

language, or any modification thereto, in a future order to be issued in this proceeding. 

The Commission therefore defers responding to the requests for rehearing and 

clarification on this subject pending further action in the forthcoming order. 

(3) General

932. In response to commenter requests, the Commission addressed a number of other 

issues in Order No. 890 related to the undesignation of network resources. Among other 

things, the Commission denied a request that network customers be given the flexibility 

to substitute new designated network resources without abandoning the original 

transmission queue position of the existing designated network resource. The 

Commission explained that granting the request would, without any apparent 

justification, put point-to-point customers seeking ATC freed up by an undesignation at a 

disadvantage. Pending the implementation of new OASIS functionality to accept 

electronic requests to designate and undesignated network resources, the Commission 

stated that network customers could submit their requests by transmitting the required 

information to the transmission provider by telefax or providing the information by 

telephone over the transmission provider’s time recorded telephone line. 

 343 Preventing Undue Discrimination and Preference in Transmission Service, 

Notice Granting Extension of Effective Date, 120 FERC ¶ 61,222 (2007). 
Docket No. RM05-17-001, et al. - 491 -

933. The Commission clarified that a network customer may only enter into a thirdparty power sale from a designated network resource if the third-party power purchase 

agreement allows the seller to interrupt power sales to the third party in order to serve the 

designated network load. The Commission stated that such interruptions must be 

permitted without penalty, to avoid imposing financial incentives that compete with the 

network resource’s obligation to serve its network load. The Commission also clarified 

that firm third-party sales may be made from an undesignated portion of a network 

customer’s network resources (i.e., a “slice-of-system sale”), so long as all of the 

applicable requirements are met. The Commission stated that the network customer must 

submit undesignations for each portion of the resource supporting the third-party sale. 

934. The Commission rejected requests to relax rules for changing the undesignation of 

network resources at any time to handle system emergencies, force majeure events, 

forced outages or unusual weather conditions. The Commission explained that other 

procedures such as those in NERC’s standard for Capacity & Energy Emergencies, EOP002-2, or the possible use of capacity benefit margin are more appropriate to deal with 

legitimate system emergencies. In situations where a request to undesignate a network 

resource cannot be accommodated without jeopardizing reliability, the Commission 

stated that the transmission provider could deny the request. 

Requests for Rehearing and Clarification

935. Bonneville argues that, if the only ATC on a path is the ATC freed up by an 

undesignation, then the network customer should be granted use of that ATC for its 

requested alternate service. Bonneville contends that such a policy would not adversely 
Docket No. RM05-17-001, et al. - 492 -

affect customers because, if the customer that is undesignating a resource is not placed 

first in line for the capacity made available by the undesignation, that customer would not 

undesignate (since it will continue to need the capacity on its existing path) and no 

capacity would be freed up for others. Bonneville concludes that refusing to place the 

undesignating customer first in line for the freed-up ATC will harm that customer while 

advantaging no one. Bonneville suggests that allowing such redirects of network 

resources would be particularly helpful for intermittent resources such as wind, given that 

transmission customers with state-mandated renewable resource requirements may wish 

to redirect for a short-term period to import renewable energy, but may be unable to do so 

on a constrained path if they are unable to utilize the capacity they are freeing up by the 

request to undesignate. 

936. Several petitioners request rehearing or clarification with respect to the 

Commission’s finding in Order No. 890 that network customers making firm third-party 

system sales from network resources must undesignate each portion of each resource 

supporting the third-party sales. 344 Petitioners generally argue that requiring a network 

customer to keep track of the individual generating units and amounts of generation from 

each unit being used to supply a system sale is unduly burdensome or impossible. South 

Carolina E&G argues that, between the scheduling deadline and the time when service 

commences, any number of events can change the available generating units being 

 344 E.g., Duke, EEI, and South Carolina E&G. Pacific Northwest IOUs raise 

similar issues in their post-tech conference comments. 
Docket No. RM05-17-001, et al. - 493 -

dispatched, change the merit order dispatch, or cause dispatch of additional units. Joined 

by EEI, South Carolina E&G asks the Commission to allow slice of system sales from a 

generation fleet by undesignating the amount of the sale. 

937. Duke states that the Commission’s policies are clear that for off-system system 

sales a generating resource must be identified on a specific basis for purposes of 

arranging point-to-point transmission service to support the off-system sale. However, 

with regard to identifying which generating units will be used to generate the energy to 

make on-system system sales, Duke argues that the Commission has never required that 

particular units or portions of units be identified and undesignated on a unit-by-unit basis. 

Duke contends that all generating units that comprise the “system” are used to serve all 

loads, and the undesignation process should occur through the recognition that a share of 

the generation system is used for retail native load and a share is used for wholesale 

native load (i.e., requirements customers) and off-system firm load. Duke maintains that 

this approach is reasonable and ensures that the transmission provider is not doublecounting or double-reserving transmission capacity needed to serve such loads, and is 

purchasing point-to-point service that is needed. 

938. E.ON U.S. argues that the Commission has provided insufficient protection for 

LSEs and others that may need to recall undesignated resources for use to supply native 

load during times of system emergencies. E.ON U.S. asks the Commission to make clear 

in the pro forma OATT that the obligation to serve native load may require the 

redesignation of network resources in times of system emergency. Absent such a 

clarification, E.ON U.S. argues that LSEs will be reluctant to make network resources 
Docket No. RM05-17-001, et al. - 494 -

available to serve the market and, in a time of emergency, confusion may occur regarding 

the proper procedure for redesignating resources. 

939. Pacific Northwest IOUs and South Carolina E&G request clarification in their 

post-technical conference comments that a network resource does not have to be 

undesignated before it is used to support the provision of reserve energy under a regional 

reserve sharing arrangement. E.ON U.S. requests similar clarification, arguing that 

flexible undesignation rules are necessary to allow utilities to quickly respond under 

reserve-sharing arrangements. Together, they argue that the failure to provide such 

clarification, and the related complications and potential sanctions, could impede or 

destroy reserve sharing arrangements and/or seriously imperil system reliability. South 

Carolina E&G proposes that the Commission expressly redefine network load under the 

pro forma OATT to include responses by the transmission provider to requests for 

emergency assistance or calls for reserves under reserves sharing agreements. If the 

Commission concludes that the undesignation requirements apply to designated network 

load used for reserve sharing purposes, E.ON U.S. proposes to post on OASIS 

information regarding its reserve sharing events within five days of the end of each 

month in which an event occurred. E.ON U.S. states that the particular units used to meet 

its reserve sharing obligation are not known until it performs an after-the-fact, monthly 

allocation of the highest-cost resources to off-system sales. 

940. MidAmerican requests clarification that, during the period until improved OASIS 

functionality is available for designating and undesignating network resources, electronic 

transmissions and email are acceptable means of designating and undesignating network 
Docket No. RM05-17-001, et al. - 495 -

resources. MidAmerican argues that electronic transmittals are similar to the already 

accepted telefax and recorded telephone line procedures, in that they provide a quick, 

efficient means of communication that can be readily stored. 

941. NRECA requests rehearing of the Commission’s determination that transmission 

providers have the discretion to deny undesignations of network resources. NRECA 

argues that the Commission has given transmission providers the ability to unduly 

discriminate against its wholesale customers (i.e., its direct competitors). Because the 

transmission provider is not likely to deny its own undesignation requests, NRECA 

contends that comparability requires that it not be allowed the ability to deny 

undesignation requests of its network customers. NRECA argues that while the actual 

scheduling of a resource could affect reliability, there should be no reliability effects from 

the mere designation or undesignation of a resource. NRECA contends that there are 

many other standards and procedures in place to protect against insufficient capacity. 

942. If the Commission retains the ability to deny a request to terminate the designation 

of a network resource, NRECA asks the Commission to at least require that denials come 

at the direction of the reliability coordinator, rather than the transmission provider. 

NRECA argues that denying the undesignation of a network resource is akin to 

designating the resource as a “must-run" generating resource. If the resource is owned by 

the network customer, NRECA maintains that the reliability coordinator should be able to 

designate the unit as a reliability-must-run unit and compensate the network customer for 

its dispatch. If the resource is not owned by the network customer, NRECA argues that 

nothing in the FPA authorizes the Commission to require the network customer or the 
Docket No. RM05-17-001, et al. - 496 -

owner of the resource to continue to contract for service with each other or use any 

particular capacity for a specific purpose. 

943. TAPS seeks clarification that a transmission provider could deny a request to 

undesignate a network resource only in the context of requests for temporary 

undesignation. TAPS argues that there are circumstances in which a resource is simply 

not available because, for example, it is incapable of continued operation or no longer 

economically viable or, in the case of a purchase, the contract has ended. 

944. MidAmerican asks that transmission providers be required to explicitly approve or 

deny requests to undesignate network resources and that the timing of action on 

undesignation requests be made consistent with the timing requirements to designate a 

network resource. MidAmerican argues that clarification is necessary to avoid confusion 

when one customer is undesignating a network resource so that another customer may 

designate it, otherwise a customer could be attempting to designate a resource before the 

request to undesignate has been addressed. 

945. Bonneville argues that the Commission should not require network resources to be 

temporarily undesignated to make firm third-party power sales if the transmission 

provider’s ATC methodology already assures that ATC has not been withheld to 

accommodate the underlying designation. Bonneville maintains that its transmission 

customers usually designate as network resources power purchase agreements sourced 

from the resources that comprise the interconnected hydroelectric system. Bonneville 

argues that its ATC methodology, which is based on historical usage data, addresses the 
Docket No. RM05-17-001, et al. - 497 -

Commission’s concerns about the availability of ATC without further requiring network 

resources to be undesignated prior to making third-party sales from those resources. 

Commission Determination

946. We disagree with Bonneville’s argument that a customer undesignating a network 

resource should be first-in-line for the transmission capacity freed up by such a 

designation. While it may be true in some circumstances that a network customer would 

choose not to undesignate a resource if there is insufficient ATC to accommodate a 

desired alternative transaction, it does not follow that the network customer’s alternative 

transaction should be put ahead of other competing requests in the queue. That would 

undermine long-standing policies governing the priority of service requests and unduly 

preference network customers. The Commission rejects similar requests by point-topoint customers to be first in line for ATC in section III.D.4.b. 

947. With regard to the undesignation of units used to supply system sales, we clarify 

that portions of the seller’s individual network resources supporting a sale of system 

power do not need to be undesignated so long as the system sale is itself designated as a 

network resource by the buyer. Instead, the seller should undesignate a portion of its 

system equal to the amount of the system sale, but which is not attributed to any specific 

generators. If the system sale is not designated as a network resource by the buyer, the 

seller must submit undesignations for each portion of each resource supporting the thirdparty sale. Since we believe most, if not all, system sales sourced from designated 

network resources are themselves designated as network resources by the buyer, we 

expect that few system sales will require undesignation on a unit-by-unit basis. 
Docket No. RM05-17-001, et al. - 498 -

948. As we reiterate in section III.D.9.c there is also no need to undesignate network 

resources prior to making sales that permit curtailment without penalty to serve the 

seller’s native load.345 Since there is no need to undesignate resources to make such 

sales, there is no corresponding need to redesignate those resources in times of 

emergency when power is recalled to serve native load. We therefore disagree with 

E.ON U.S. that special redesignation procedures are necessary for LSEs selling recallable 

energy. In response to Pacific Northwest IOUs and South Carolina E&G, we amend 

sections 1.26 and 30.4 of the pro forma OATT to make clear that network resources do 

not have to be undesignated before they are used to support the provision of reserve 

energy under a Commission-approved reserve sharing agreement. 

949. In response to MidAmerican’s request, we clarify that, pending implementation of 

the new OASIS functionality, submission of requests to designate and undesignate 

network resources may be provided by any appropriate electronic procedures established 

by the transmission provider, or by telephone or telefax as provided in Order No. 890.

950. We grant NRECA and TAPS’ request for rehearing of the Commission’s decision 

in Order No. 890 to allow transmission providers to deny requests to terminate network 

resource designations in certain situations. Upon consideration of petitioners’ arguments, 

we agree that it is not appropriate to allow the transmission provider to deny 

undesignation, effectively requiring the network customer to continue to make available a 

 345 See Order No. 890 at P 1459; see also WPPI 84 FERC at 61,152. Curtailment 

contemplates a reduction in service as a result of system reliability conditions, not 

economic reasons. 
Docket No. RM05-17-001, et al. - 499 -

resource that the customer is unable to, or no longer wishes to, make available. 

Reliability problems caused by the lack of available resources should be dealt with 

through other means, such as negotiation of must-run service agreements. In light of this 

decision, MidAmerican’s request to establish a time by which a transmission provider 

must act on a request to terminate the designation of a network resource is rejected as 

moot. 

951. We disagree with Bonneville that the pro forma OATT should be amended to 

allow for firm third-party sales from a network resource without first undesignating the 

network resource. If the particular ATC methodology used by the transmission provider 

allows for flexibility in implementing this requirement, the transmission provider may 

propose a variation to the pro forma OATT in an FPA section 205 filing. Any such 

request should adequately address the Commission’s concern, as stated in Order No. 888, 

that network customers may (absent a prohibition on network resources including any 

portion of a resource that was committed for sale to a third party) have the incentive to 

specify unlimited generation resources to be integrated into their load without any 

commensurate financial obligation, given that network transmission service is billed on a 

load ratio basis.346

 346 See Order No. 888 at 31,753-54. 
Docket No. RM05-17-001, et al. - 500 -

6. Clarifications Related to Network Service

a. Secondary Network Service

952. In Order No. 890, the Commission declined to adopt further limitations to the use 

of secondary network service under section 28.4 of the pro forma OATT, which allows a 

network customer to deliver energy to its network load from non-designated network 

resources on an as-available basis without additional charge. Although the Commission 

had proposed in the NOPR to limit the proper use of secondary network service to 

deliveries of economy energy only, upon review of comments submitted on this issue the 

Commission concluded that there were instances outside of the proposed definition of 

economy energy that warranted the use of secondary network service. The Commission 

therefore decided to retain the existing section 28.4 of the pro forma OATT that allows 

the use of secondary network service “to deliver energy to its Network Loads.” 

Requests for Rehearing and Clarification

953. Idaho Power asks the Commission to clarify the showing that transmission 

customers must make to demonstrate that they are using secondary network service 

properly or not using secondary network service to support off-system sales. Idaho 

Power states that several commenters lamented in response to the NOPR the difficulties 

of making the calculations necessary to demonstrate that secondary network service is not 

being used to support off-system sales. Idaho Power contends that the Commission has 

never clearly articulated the test used to determine improper use of network service. 

Although Idaho Power acknowledges that the Commission has provided some guidance 

on these issues in audit and investigation reports, Idaho Power states that it is unclear to 
Docket No. RM05-17-001, et al. - 501 -

what extent the Commission intends language in such reports to apply beyond the context 

of the particular audit or investigation. 

954. Idaho Power suggests that an economic test would not be precise enough to 

address all the circumstances where network and secondary transmission should be used. 

Idaho Power asks that the Commission instead consider three factual questions to 

evaluate the proper use of secondary network service: whether the utility’s decisions were 

intended to maintain a balanced portfolio for service to load; whether the off-system sale 

was made at a time when the utility’s resources exceeded its expected load and needed to 

balance its portfolio; and, whether the utility either actually needed the imported energy 

to serve load or needed the imported energy to replace a more expensive resource that 

otherwise would have been used to serve load. If the answer to these questions is “yes,” 

then Idaho Power argues that the use of network or secondary transmission should always 

be allowed to import energy. 

955. Idaho Power also asks the Commission to articulate the types of records it expects 

a utility to maintain in order to document the use of its transmission network in 

compliance with Commission requirements. In Idaho Power’s view, clarification of the 

rules and corresponding documentation requirements will allow utilities and other 

network customers to become more comfortable using secondary network service rather 

than buying excessive amounts of point-to-point transmission. 

Commission Determination

956. The Commission affirms the decision in Order No. 890 to retain the existing test 

for eligibility to use secondary network service, i.e., when energy is delivered to serve 
Docket No. RM05-17-001, et al. - 502 -

network loads. In rejecting the proposed restriction to deliveries of economy energy, the 

Commission recognized that there may be instances that warrant the use of secondary 

service in order to serve network loads reliably that would not satisfy an economic test, as 

Idaho Power suggests. The Commission declined to adopt other restrictions on the use of 

secondary network service proposed by commenters, expressing concern that the 

proposals could preclude legitimate use of secondary network service. 

957. We similarly conclude that the alternative three-part factual test proposed by Idaho 

Power might not reflect all of the factors to be considered in determining whether a 

particular use of secondary network service was to deliver energy to network loads. The 

Commission did not preclude in Order No. 890 consideration of whether the delivery in 

question is economic energy and, instead, determined that restricting the use of secondary 

network service only to economic energy would be too severe. The primary focus of the 

Commission’s analysis is whether the energy delivered using secondary network service 

was intended to serve network load. Whether a delivery in question is for economic 

energy may very well be relevant when considering intent, but so would 

contemporaneous documentation and other evidence. We will continue to address the 

appropriate use of secondary network service on a case-by-case basis, as in 

MidAmerican,

347 which we intend to serve as guidance to the industry regarding the 

appropriate use of secondary network service and the documentation that would be 

relevant for analysis. 

 347 MidAmerican Energy Co., 112 FERC ¶ 61,346 at P 6 (2005) (MidAmerican). 
Docket No. RM05-17-001, et al. - 503 -

b. “On an as-available basis”

958. The Commission clarified in Order No. 890 that secondary service must be 

requested in accordance with section 18, including the timing restrictions set forth in 

section 18.3 of the pro forma OATT. The Commission explained that secondary service 

is on an as-available basis and that network customers should not be allowed to lock in 

such service in advance of other non-firm uses of available transmission. The 

Commission concluded that allowing lower priority secondary service to have a 

scheduling advantage over non-firm transmission would be inappropriate and would 

discourage the use of non-firm transmission service. 

Requests for Rehearing and Clarification

959. Several petitioners request clarification regarding the priority level of secondary 

network service in relation to non-firm transmission service. NRECA, Southern, and 

TDU Systems ask the Commission to clarify that secondary service has a higher priority 

than non-firm point-to-point service. These petitioners state that section 28.4 of the pro 

forma OATT grants secondary service a higher priority than all non-firm point-to-point 

service and that the Commission’s reference to secondary network service as “lowerpriority” in Order No. 890 is incorrect and contradictory of Order No. 888. Without a 

higher priority for secondary network service, these petitioners contend that network 

customers located in constrained regions who are forced to rely on secondary service will 

be worse off and reliability will be impaired. 

960. Joined by TAPS, NRECA argues that application of the scheduling requirements 

for non-firm point-to-point service to network customer reservations of secondary service 
Docket No. RM05-17-001, et al. - 504 -

would present a serious set-back for LSEs. NRECA states that its members commonly 

use secondary service to import long-term firm power from other states into their home 

states in order to serve native load. NRECA argues that this use of secondary service 

could not happen if network customers were held to the timing restrictions in section 

18.3. NRECA contends that precluding network customers from acquiring secondary 

service to coincide with long-term generation requirements, but before actual use of the 

transmission, would contradict Congressional intent to preserve and enhance network 

service to native load. 

961. NRECA further contends that there is no evidentiary record for finding that the 

existing practice of scheduling secondary service without regard to the time restrictions 

of section 18.3 has “discouraged” the use of non-firm transmission service or minimized 

associated revenue credits. Even if that is the case, NRECA argues that secondary 

network service customers should have priority and any marginal amount of foregone 

revenues is justified by more reliable, economic service for LSEs. Because network 

customers pay a load ratio share of total transmission costs regardless of whether their 

energy is coming from designated network resources or non-designated network 

resources on an as-available basis, NRECA concludes that network customers use the 

transmission system in a fundamentally different way from non-firm users and, therefore, 

they should not be held to the same timing restrictions in 18.3 that apply to non-firm 

customers. 

962. TAPS argues that, as long as network customers bear a full share of the costs of 

operating the entire system, they should have first call on non-firm use, just as secondary 
Docket No. RM05-17-001, et al. - 505 -

network service is the last non-firm use to be curtailed in response to constraints. In the 

event the Commission denies rehearing on this issue and retains the new timing 

restrictions on secondary service, TAPS asks that transmission providers also be required 

to abide by those same requirements when they seek to use an undesignated resource (or 

the undesignated portion of a resource) to service their native load. 

Commission Determination

963. The Commission grants clarification of the reference to “lower-priority” 

secondary network service in paragraph 1606 of Order No. 890, which was intended to 

distinguish secondary network service from firm transmission service, not non-firm 

transmission service. Section 28.4 of the pro forma OATT affords secondary service a 

higher curtailment priority than any non-firm point-to-point service and the Commission 

did not intend to imply otherwise in Order No. 890. We disagree, however, that 

secondary service should be allowed a higher scheduling priority compared to all other 

non-firm service. Secondary service is on an “as available” basis and, therefore, network 

customers should not be allowed to lock in such service in advance of other non-firm 

uses of available transmission. 

964. Petitioners’ arguments to the contrary are misplaced. Although FPA section 217 

does address LSE uses of the transmission systems, the focus of that provision is on the 

use of firm transmission, not non-firm uses such as secondary network service. The fact 

that network customers pay a load ratio share of transmission costs does not grant them 

superior rights when scheduling firm transmission, nor should it justify superior rights 

when scheduling uses of the transmission system other than firm uses. Any request for 
Docket No. RM05-17-001, et al. - 506 -

secondary network service therefore must be made in compliance with section 18, 

including the timing restrictions set forth in 18.3, of the pro forma OATT. In response to 

TAPS, we reiterate that section 28.2 of the pro forma OATT requires the transmission 

provider to designate resources and loads in the same manner as any network customer. 

c. Behind the Meter Generation and Uses of Point-to-Point 

Service

965. The Commission declined to require transmission providers to allow netting of 

behind the meter generation against transmission service charges to the extent customers 

do not rely on the transmission system to meet their energy needs, stating that 

commenters had not provided any different arguments not fully addressed in Order No. 

888. The Commission explained that the existing pro forma OATT already allowed 

transmission customers to exclude the entirety of a discrete load from network service 

and serve such load with the customer’s behind the meter generation and point-to-point 

transmission service as necessary, thereby reducing the network customer’s load ratio 

share. The Commission concluded it is most appropriate to continue to review alternative 

transmission provider proposals for behind the meter generation treatment on a case-bycase basis. 

Requests for Rehearing and Clarification

966. Washington IOUs contend that the language added to section 30.4 of the pro 

forma OATT in Order No. 890 appears to permit a transmission provider or network 

customer to take point-to-point service to deliver power from remote network resources 

to loads in certain instances. Washington IOUs ask the Commission to clarify that a 
Docket No. RM05-17-001, et al. - 507 -

transmission provider or network customer may use short-term firm point-to-point 

service to serve native load or network load, respectively. Washington IOUs state that 

there are at least two events in which the use of point-to-point service to serve native or 

network load is needed and appropriate: the need to import power when it is unclear 

whether or not the power will be deemed to be used to serve native or network load 

because of its relative cost; and the need to import power reliably from non-designated 

network resources in order to serve native or network load, instead of relying on 

secondary network service. In their view, a restriction on the use of point-to-point 

service would prevent the transmission provider and network customer from competing 

for scarce transmission capacity in order to serve their native or network load. 

967. Idaho Power similarly asks the Commission to clarify whether a network customer 

or transmission provider could use point-to-point transmission to serve load in addition 

to, and not in place of, paying its full load ratio share for use of the network. Idaho 

Power contends that a transmission provider or network customer should have the option 

to compete in the market for point-to-point service when it is not sure at the time of a 

purchase whether the energy will be needed for load or sold off-system as surplus, 

provided they pay the full value of point-to-point service. Alternatively, Idaho Power 

requests the Commission clarify that the network customer and the transmission provider 

may procure firm point-to-point service in order to serve native and network load when 

the utility requires capacity in addition to the existing network reservations or secondary 

transmission over an interface. In order to ensure that network and secondary 

transmission rights are not being used to support off-system sales, Idaho Power contends 
Docket No. RM05-17-001, et al. - 508 -

that the use of network transmission rights must be minimized and used in combination 

with point-to-point service. 

968. Idaho Power also requests clarification that the following examples are considered 

proper uses of network transmission, secondary transmission and point-to-point 

transmission. First, use of point-to-point transmission to accomplish an off-system sale 

entered into at a time the utility was forecasted to be long, even if followed by a 

subsequent purchase to serve load using secondary network service or point-to-point 

transmission if the utility becomes short. Second, use of a combination of network 

service, secondary network service, or point-to-point transmission for a purchase at a 

time the utility was forecasted to be short, even if followed by a subsequent sale using 

point-to-point transmission from a portion of that resource that becomes excess due to a 

drop in forecasted load. Third, and related, use of network transmission for a purchase 

expected to serve load, even if followed by a subsequent sale using point-to-point service 

from a portion of that resource that becomes excess in real-time. Fourth, use of point-topoint service to purchase economic energy to serve network load in conjunction with an 

off-setting undesignation of network resources and sale of energy off system using pointto-point transmission. Finally, use of secondary network service to purchase economic 

energy to serve network load in conjunction with an off-setting undesignation of network 

resources and sale of energy off system using point-to-point transmission. Idaho Power 

contends that only the last example should involve an economic test to demonstrate that 

the imported resource will displace a resource in the utility’s load service stack of 

resources. 
Docket No. RM05-17-001, et al. - 509 -

969. TAPS and FMPA argue that the Commission failed to consider in Order No. 890 

the circumstance when it is physically impossible for the transmission system to actually 

deliver a customer’s full load, which they contend was not addressed in Order No. 888.348 

TAPS states that the Commission’s proposed solution of the exclusion of the entirety of a 

discrete load from network service is no help to a customer that is served through a single 

delivery point and, therefore, has no discrete load that could be service through a 

combination of point-to-point service and behind the meter generation while other load 

takes network service. FMPA argues that it is unjust to charge a customer for service that 

cannot be provided and, therefore, there should be an exception to load ratio share pricing 

when the transmission provider is unable to serve the network customer’s entire load. 

Commission Determination

970. As stated in Order No. 890, the pro forma OATT permits transmission customers 

to exclude the entirety of a discrete load from network service and serve such load with 

the customer’s behind the meter generation and through any needed point-to-point 

transmission service, thereby reducing the network customer’s load ratio share.349 In 

other situations, use of point-to-point service by network customers is in addition to 

network service and therefore does not serve to reduce their load ratio share. As the 

Commission concluded in Order No. 888-A, transmission customers ultimately must 

evaluate the financial advantages and risks and choose to use either network integration 

 348 Citing Florida Mun. Power Agency v. FERC, 411 F.3d 287, 291 (D.C. Cir. 

2005).

349 See Order No. 890 at P 1619. 
Docket No. RM05-17-001, et al. - 510 -

or firm point-to-point transmission service to serve load.350 Any alternative transmission 

provider proposals for behind the meter generation treatment will be reviewed on a caseby-case basis.351

971. With regard to concerns of insufficient transmission to serve the network 

customer’s full load, we fail to understand how, under normal circumstances, the 

transmission provider has no capacity to service a load that has been designated by the 

network customer. Once a load has been designated, it is the obligation of the 

transmission provider to serve that load and to plan its system so that the load can be 

accommodated in the future. To assist the transmission provider in fulfilling that 

obligation, network customers are required to provide load forecasts to the transmission 

provider each year. The transmission planning reforms adopted in Order No. 890 will 

add greater transparency to this planning process, better enabling network customers to 

understand how their needs are reflected in the development of the transmission system. 

To the extent a transmission provider is unable to satisfy its obligation to serve a 

designated network load, it is more appropriate to address that situation on a case-by-case 

basis. 

972. The Commission also declines to address here the hypothetical scenarios offered 

by Idaho Power. Any determination regarding the appropriate use of secondary, network, 

or point-to-point service will depend upon the facts surrounding the use of such services. 

 350 Order No. 888-A at 30,260-61. 

351 See, e.g., PJM Interconnection, L.L.C., 113 FERC ¶ 61,279 (2005). 
Docket No. RM05-17-001, et al. - 511 -

While load forecasts may change and weather related incidents may occur, with 

corresponding implications for a utility’s purchasing activities, it is most appropriate for 

the Commission to consider whether a particular transaction is an appropriate use of 

secondary network service based on the facts and circumstances surrounding the 

transaction, as discussed above. 

7. Transmission Curtailments

973. The Commission did not propose in the NOPR, or adopt in Order No. 890, any 

changes to the terms and conditions under which a transmission provider may curtail 

service to maintain reliable operation of the grid, as set forth in sections 13.6 and 14.7 for 

point-to-point service and section 33 for network service. The Commission did, however, 

conclude that the posting of additional curtailment information is necessary to provide 

transparency and allow customers to determine whether they have been treated in the same 

manner as other transmission system users, including customers of the transmission 

provider. Accordingly, the Commission required transmission providers, working through 

NAESB, to develop a detailed template for the posting of additional information on OASIS 

regarding firm transmission curtailments, including all circumstances and events 

contributing to the need for a firm service curtailment, specific services and customers 

curtailed (including the transmission provider’s own retail loads), and the duration of the 

curtailment. 

Requests for Rehearing and Clarification

974. Powerex claims the Commission improperly rejected its request that the pro forma

curtailment provisions be modified to provide for pro rata curtailment based on a 
Docket No. RM05-17-001, et al. - 512 -

customer's reserved capacity rather than its scheduled capacity. Powerex states that the 

Commission appears to have misunderstood its proposed two-stage curtailment procedure, 

which was rejected for having the potential to impair reliability since the amount of 

capacity curtailed using that approach would not address the actual power flows and, 

therefore, could be less than required to relieve the overloaded facility. Powerex explains 

that the proposed two-stage process pertained solely to the timeframe before power is 

actually flowing. Powerex further states that pro rata curtailments based on reservation 

capacity would be made prior to the energy scheduling and tagging deadline (e.g., 20 

minutes before the operating hour), that the transmission provider would compare a 

customer's individual schedule to its reduced/curtailed rights, and, if the customer's 

scheduled quantities fall within its reduced rights, that schedule would flow uncut. After 

calculating the total capacity scheduled following the application of the pro rata

curtailment, Powerex proposes that any excess transmission be allocated back on a pro rata

basis to transmission customers whose schedules were cut below their reduced rights. 

Powerex states that this would in no way affect curtailments to actual power flows. 

Powerex suggests that curtailment within the hour, due to the limited time available to 

affect relief, should continue to be allocated based on actual schedules. 

975. Powerex contends that the Commission mistakenly concluded that Powerex's 

proposal would adversely impact reliability, arguing that the amount of capacity curtailed 

under the two-stage process would be no different from the amount of capacity the 

transmission provider believes is necessary to address the constraint and that the capacity 

would be more equitably and economically cut according to the transmission customers' 
Docket No. RM05-17-001, et al. - 513 -

reserved quantities rather than the scheduled quantities. Powerex states that it is not aware 

of a single commenter that provided any evidence that the above modification would be 

detrimental in any way to reliability, nor did the Commission provide any evidentiary 

support for its response. 

976. E.ON U.S. requests clarification of the correct order of curtailments given the 

addition of conditional firm point-to-point transmission service. Specifically, E.ON U.S. 

requests clarification regarding the curtailment priority of the different conditional firm 

options, i.e., conditions based on an annual number of hours and conditions based on 

specific system conditions. 

Commission Determination

977. The Commission rejects Powerex’s request to modify the curtailment provisions of 

the pro forma OATT to provide for pro rata curtailment based on a customer’s reserved 

capacity rather than its scheduled capacity. Although Powerex addresses in its request for 

rehearing the Commission’s initial concern regarding the proposal,352 we continue to 

believe that the proposal would have a potentially adverse impact on reliability. Powerex’s 

proposal would greatly increase the complexity of scheduling transactions at or near realtime operations, threatening reliability without providing significant competitive benefits. 

Powerex has taken a complex issue and presented it in two simple steps, leaving out the 

details of how the transmission operators could obtain all the necessary information 

 352 See Order No. 890 at P 1629 (stating that the amount of capacity actually 

curtailed under the Powerex proposal might be less than required to relieve the 

overloaded facility). 
Docket No. RM05-17-001, et al. - 514 -

required to make on-the-spot decisions, perform the analyses to determine whether each 

schedule flow fully utilizes its respective reservation, reallocate unused reserved capacity, 

and curtail transactions without impairing reliability. We thus reject the Powerex’s request 

for rehearing in this regard. 

978. In response to E.ON U.S., we reiterate that the Commission adopted a secondary 

network curtailment priority to apply for the hours or specific conditions when conditional 

firm service is conditional. During non-conditional periods, conditional firm service 

curtailment is treated consistent with curtailment of other long-term firm service.353 We 

reiterate that Order No. 890 did not change the terms and conditions under which a 

transmission provider may curtail service to maintain reliable operation of the grid or 

change the priority of curtailment for any type of transmission service. Rather, conditional 

firm point-to-point service, as adopted in Order No. 890, fits within the existing curtailment 

priorities and constructs. 

8. Standardization of Rules and Practices

a. Business Practices

979. In Order No. 890, the Commission adopted the NOPR proposal to continue to 

require that only those rules, standards, and practices that significantly affect 

transmission service be incorporated into a transmission provider’s OATT. The 

Commission affirmed the use of a “rule of reason” to determine what rules, standards, 

 353 See id. at P 1074. 
Docket No. RM05-17-001, et al. - 515 -

and practices significantly affect transmission service and, as a result, must be included in 

the transmission provider’s OATT. 

980. Regarding rules, standards, and practices that relate to transmission service, but 

are not included in the OATT, the Commission required transmission providers to post 

this information on their public websites and make it accessible via OASIS. The 

Commission made this requirement applicable to all such rules, standards, and practices, 

currently written or otherwise.354 The Commission stated that it would not be appropriate 

to place the rules, standards, and practices only on OASIS, as some transmission 

providers use certificates to restrict access to their OASIS sites. The Commission 

amended section 4 of the pro forma OATT to establish this posting requirement. 

981. The Commission also required each transmission provider to post on its public 

website, with a corresponding link on OASIS, a statement of the process by which the 

transmission provider will amend the rules, standards, and practices that relate to 

transmission service, but which are not included in the OATT. The Commission stated 

that this process must include a mechanism to provide reasonable notice of any proposed 

 354 With respect to the business practices developed by NAESB, the Commission 

noted that there may be copyright restrictions that limit the transmission provider’s ability 

to post those practices on its own website. In such instances, the Commission stated its 

expectation that the transmission provider will reference any NAESB practices it uses 

and provide a link on its public website to the copyrighted material on the NAESB 

website. 
Docket No. RM05-17-001, et al. - 516 -

changes to a posted business practice and the respective effective date of such change.355 

Section 4 of the pro forma OATT was further amended to formalize this posting 

requirement. 

982. Finally, the Commission adopted the NOPR proposal to amend the pro forma

OATT by including a new Attachment L specifying the qualitative and quantitative 

criteria that the transmission provider uses to determine the level of secured and 

unsecured credit required. The Commission determined that Attachment L must contain 

the following elements: (1) a summary of the procedure for determining the level of 

secured and unsecured credit; (2) a list of the acceptable types of collateral/security; (3) a 

procedure for providing customers with reasonable notice of changes in credit levels and 

collateral requirements; (4) a procedure for providing customers, upon request, a written 

explanation for any change in credit levels or collateral requirements; (5) a reasonable 

opportunity to contest determinations of credit levels or collateral requirements; and (6) a 

reasonable opportunity to post additional collateral, including curing any noncreditworthy determination. The Commission stated that the transmission provider could 

supplement Attachment L with a credit guide or manual to be posted on OASIS. 

Requests for Rehearing and Clarification

983. TDU Systems contend that the Commission’s filing standard suggests that the 

“rule of reason” test will only come into play after it has determined that a particular 

 355 The Commission permitted transmission providers to adopt such additional 

procedures they deem appropriate, such as opportunities for comment to proposed 

changes to rules, standards, and practices. 
Docket No. RM05-17-001, et al. - 517 -

practice is one that significantly affects transmission service. TDU Systems argue that, 

once the Commission has determined that a practice significantly affects rates and 

services, the only remaining question is whether the practice is realistically susceptible of 

specification and is not so generally understood in any contract or arrangement as to 

render recitation superfluous.356 TDU Systems contend that Order No. 890 is an 

unexplained departure from prior precedent and that the Commission failed to justify its 

limitation on the data to be included in the OATT. 

984. In order to increase certainty, TDU Systems also requests that the Commission 

specify in advance the different categories of transmission provider issuances that the 

Commission expects to see in the tariffs. At a minimum, TDU Systems asks that the 

Commission clarify that any rule, standard, or practice that can serve to limit a 

transmission customer’s access to transmission service is one that significantly affects 

transmission service and, therefore, should be included in the OATT. 

985. Old Dominion requests that the Commission clarify that, for individual 

transmission-owning members of an RTO that do not maintain their own OATT, the 

transmission owners must comply with the requirements of Order No. 890 by including 

in the RTO’s OATT any rules, standards and practices that affect transmission service 

that are either different from or an expansion upon those in the RTO’s OATT. Old 

Dominion states that this is necessary because individual transmission owners’ planning 

 356 Citing City of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985) (City 

of Cleveland). 
Docket No. RM05-17-001, et al. - 518 -

criteria and business practices can limit access to transmission service in the same 

manner as those of the RTO. 

986. NRECA states that it supports the Commission’s decision to require each 

transmission provider to post on its public website (with a corresponding link on OASIS) 

all rules, standards or business practices that relate to the terms and conditions of 

transmission service, if not already stated in the OATT itself. NRECA contends, 

however, that the Commission’s subsequent discussion of transmission providers’ credit 

guides or manuals seemingly allows that information to be posted only on OASIS.357 

Because credit is such an important potential barrier to transmission access, NRECA 

maintains that it is critical for the details of the credit criteria and methodologies to be 

posted on the public website of the transmission provider, with a link on OASIS. 

NRECA also contends that a statement should be added to the first paragraph of 

Attachment L explicitly clarifying that the credit review procedures and criteria may not 

unfairly disadvantage public power entities or other customer groups having 

unconventional financing or business structures. 

987. Southern requests that the Commission grant rehearing to allow a transmission 

provider that does not restrict access to its OASIS site the option of posting rules, 

standards and practices relating to transmission service on its OASIS with a link to such 

information on its public website. Southern maintains that permitting transmission 

providers that do not restrict access to their OASIS to make required postings on OASIS 

 357 Citing Order No. 890 at P 1657-58. 
Docket No. RM05-17-001, et al. - 519 -

would satisfy the Commission’s objective to provide public access to such information. 

Southern argues that not allowing such flexibility would be arbitrary and capricious. 

Commission Determination

988. The Commission did not intend, as TDU Systems suggest, that the Commission 

must first determine that a particular practice significantly affects transmission service 

before it applies the “rule of reason.” In Order No. 890, the Commission “affirm[ed] the 

use of a ‘rule of reason’ to determine what rules, standards, and practices significantly 

affect transmission service and, as a result, must be included in the transmission 

provider’s OATT.”358 Specifically, the “rule of reason” requires “recitation of only those 

practices that affect rates and services significantly, that are realistically susceptible of 

specification, and that are not so generally understood as to render recitation 

superfluous.”359 The Commission intends to continue to use the “rule of reason” for this 

purpose, consistent with its statutory responsibility and precedent. 

989. We decline to specify in advance the particular categories of rules, standards, and 

practices that must be documented in the transmission provider’s OATT. Although rules, 

standards, and practices that limit a transmission customer’s access to transmission 

service may very well have a significant effect on transmission services, and therefore 

should be in the OATT, any attempt to list the specific categories of rules, practices and 

 358 Id. at P 1649. 

359 Public Serv. Co. of Colo., 67 FERC ¶ 61,371 at 62,267 (1994) (quoting City of 

Cleveland, 773 F.2d at 1376). 
Docket No. RM05-17-001, et al. - 520 -

standards that must be included in an OATT would be over- or under-inclusive as applied 

to a particular transmission provider. The Commission believes that, through application 

of the “rule of reason,” we will be better able to identify those rules, standards and 

practices that significantly affect transmission service and, as a result, are required to be 

in each transmission provider’s OATT. 

990. In response to Old Dominion, we reiterate that each ISO and RTO must include in 

its OATT all of the rules, standards and practices that significantly affect the transmission 

service provided by the ISO or RTO and must electronically post all of the rules, 

standards and practices that relate to transmission service, but which are not included in 

the OATT. To the extent any of the transmission-owning members of the ISO or RTO 

have additional rules, standards and practices that significantly affect, or relate to, the 

transmission service being provided by the ISO or RTO, the ISO or RTO must include 

such rules, standards and practices in its OATT or electronic postings, as relevant. 

Transmission customers must be able to understand the rules, standards and practices that 

affect or relate to the service being provided by the transmission provider, even if such 

rules, standards or practices are developed or implemented by third parties. 

991. We agree with Southern’s request for rehearing to allow a transmission provider 

that does not restrict access to its OASIS site the option of posting rules, standards and 

practices relating to transmission service on its OASIS with a link to such information on 

its public website. The Commission is sympathetic to Southern’s concern and agrees that 

section 4 of the pro forma OATT, as revised by Order No. 890, is overly restrictive. The 

Commission’s purpose in revising section 4 was to ensure that the public has unrestricted 
Docket No. RM05-17-001, et al. - 521 -

electronic access to the transmission provider’s rules, standards and practices that are not 

included in its OATT. The Commission concludes that the transmission provider should 

be free to place this information on OASIS, its public website or other suitable electronic 

platform as long as the transmission provider provides, both on OASIS and on its public 

website, an electronic link to the information. We have revised section 4 accordingly. 

992. We also agree with NRECA that, in Order No. 890, the Commission appears to 

allow the transmission provider to post its credit guides or manuals only on OASIS.360 

This was not our intent. The Commission considers credit guides and manuals containing 

more detailed information than that required in Attachment L to be rules, standards or 

practices that relate to transmission service, that not be included in the transmission 

provider’s OATT. We clarify that the transmission provider must electronically post 

such credit guides and manuals and provide a link to that information on its public 

website and OASIS. We deny as unnecessary NRECA’s request to add a statement to 

Attachment L regarding application of credit review procedures and criteria to customer 

groups with unconventional financing or business structures. The Commission already 

provided in Order No. 890 that transmission providers must consider both quantitative 

and qualitative factors so that the particular circumstances surrounding public power 

entities can be recognized when analyzing their creditworthiness.361 

 360 See Order No. 890 at P 1657-58. 

361 See id. at P 1659. 
Docket No. RM05-17-001, et al. - 522 -

b. Limitation on Liability 

993. In Order No. 890, the Commission declined to amend the liability protections 

found in the pro forma OATT for the same reasons that the Commission rejected similar 

proposals in the past.362 The Commission relied upon the reasoning found in Order Nos. 

888-A, 888-B, 2003,363 the Reliability Policy Statement,364 and Commission precedent.365 

The Commission explained that the pro forma OATT was not intended to address 

liability issues and that liability was a separate issue from indemnification.366 The 

Commission further explained that transmission providers were not precluded from 

relying on state laws that protected utilities or others from claims founded in ordinary 

negligence.367 The Commission declined to adopt a uniform federal liability standard and 

decided that, while it was appropriate to protect the transmission provider through force 

majeure and indemnification provisions from damages or liability when service is 

 362 See, e.g., Southwest Power Pool, Inc., 113 FERC ¶ 61,287 (2005); Southern 

Company Services, Inc., 113 FERC ¶ 61,239 (2005); Nevada Power Co., 99 FERC 

¶ 61,347 (2002); Arkansas Louisiana Gas Co. v. Hall, 7 FERC ¶ 61,175, reh’g denied, 

8 FERC ¶ 61,039 (1979). 

363 Order No. 2003 at P 636; Order No. 2003-A at 31,162. 

364 Policy Statement on Matters Related to Bulk Power System Reliability, 

107 FERC ¶ 61,052 (2004) (Reliability Policy Statement). 

365 See, e.g., Northeast Utilities Services Co., 111 FERC ¶ 61,333 (2005) 

(Northeast Utilities); Southwest Power Pool, Inc., 112 FERC ¶ 61,100 at P 39 (2005); 

Southern Company Services, Inc., 113 FERC ¶ 61,239, at P 7 (2005). 

366 See Order No. 888-A at 30,301 and Order No. 888-B at 62,081 (section 10.2 of 

the pro forma OATT). 

367 Order No. 888-A at 30,301. 
Docket No. RM05-17-001, et al. - 523 -

provided by the transmission provider without negligence, it would leave the 

determination of liability in other instances to other proceedings.368 

Requests for Rehearing and Clarification 

994. Washington IOUs request that the Commission grant rehearing and establish a 

uniform liability provision in the pro forma OATT that limits transmission provider 

liability except in instances of gross negligence or willful misconduct. In their view, 

enactment of mandatory reliability standards under FPA section 215, the threat of civil 

penalties and other remedial actions, and state oversight all provide appropriate 

incentives for utilities to exercise due care in the operation of their systems. Washington 

IOUs argue that state protections do not appear to be sufficient to protect a transmission 

provider against outage liability since they have arisen in the context of claims by retail 

customers. They argue that granting liability limitations except in instances of gross 

negligence or intentional misconduct is appropriate given that outage liability is not 

necessary to ensure utilities operate their transmission systems reliably. 

995. Washington IOUs also contend that limitations of liability can be effected by 

contracts, such as the pro forma OATT, under much state law. They argue that it is 

therefore arbitrary for the Commission to expect transmission providers to rely on state 

law for appropriate limitations of liability, while preventing the inclusion of provisions in 

the pro forma OATT to effectuate such limitations of liability. Washington IOUs also 

argue that the Commission has provided no good reason for approving limitations on 

 368 Order No. 888-B at 62,081. 
Docket No. RM05-17-001, et al. - 524 -

liability for RTOs/ISOs, but not for other transmission providers. In their view, the 

policy concerns justifying liability limitations for utilities in RTOs/ISOs are identical to 

those confronting utilities in non-RTO/ISO areas. 

Commission Determination 

996. The Commission denies rehearing of the determination in Order No. 890 not to 

change the liability protections found in the pro forma OAAT. Washington IOUs raise 

no new arguments in support of their position. As the Commission explained in Order 

No. 890, proposals by public utilities to amend their OATTs to include limitations on 

liability will be considered on a case-by-case basis.369 On review of such requests, the 

Commission will consider whether state laws provide inadequate protection from 

liability.370 In response, Washington IOUs argue that state law protections appear to be 

insufficient because they arose in the context of claims by retail customers, yet petitioners 

offer no evidence that transmission providers are in fact precluded from relying on state 

law for liability protections. The potential for legal and regulatory gap is therefore not so 

great as to warrant inclusion of liability protections in the pro forma OATT for all 

transmission providers. 

997. We also disagree that there is no reason to distinguish between RTOs/ISOs and 

other transmission providers in considering requests to amend the liability standard of 

their OATTs. The Commission has provided increased liability protection to RTOs/ISOs 

 369 See Order No. 890 at P 1675 (citing Reliability Policy Statement at P 40). 

370 See Southern Company Services, Inc., 113 FERC ¶ 61,239 at P 7. 
Docket No. RM05-17-001, et al. - 525 -

because they were created by and are solely regulated by the Commission and otherwise 

would be without limitations on liability.371 Because Washington IOUs have failed to 

show that other transmission providers are similarly situated to RTOs/ISOs in this regard, 

we affirm the decision to continue to review on a case-by-case basis a request to amend 

the liability standard in a transmission provider’s OATT. 

9. OATT Definitions

998. In order to support the reforms adopted in Order No. 890 and otherwise clarify the 

requirements of the pro forma OATT, the Commission added and amended various 

definitions in the pro forma OATT. Petitioners have sought rehearing and clarification of 

certain of these definitions. 

a. Affiliate

999. In order to support reforms associated with the distribution of operational 

penalties, the Commission adopted the following definition of Affiliate in the pro forma

OATT: “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.” 

Requests for Rehearing and Clarification

1000. EEI states that the term Affiliate is used in several provisions of the pro forma

OATT that were not modified by Order No. 890. To avoid potential confusion, EEI 

 371 See id. 
Docket No. RM05-17-001, et al. - 526 -

requests that the Commission amend the pro forma OATT to capitalize every use of the 

term. 

1001. APPA requests that, consistent with Order No. 888-A, the Commission clarify that 

public power joint agencies and their members are not corporate affiliates and, therefore, 

the definition of Affiliate does not apply to public power joint action agencies for the 

purposes of applying the Standards of Conduct. APPA notes that the Commission in 

Order No. 890 concluded that the definition of Affiliate does not apply to G&T 

cooperatives and their member distribution cooperatives. APPA argues that public power 

joint action agencies and their members are similarly situated to G&T cooperatives and 

their members and, as a result, the rationale set out in Order No. 888-A and Order No. 

890 applies equally to public power agencies joint action agencies and their members.372 

APPA suggests Commission policy that supports not treating joint action agencies and 

their members as consisting of “single economic units” also supports not treating joint 

action agencies and their members as Affiliates.373

1002. E.ON U.S. requests guidance on how functionally unbundled transmission 

providers should treat their generation function for purposes of the pro forma OATT. 

E.ON U.S. states that its generation and transmission functions are owned by the same 

corporate entity, but are unbundled from each other for purposes of the Standards of 

Conduct. As a result, E.ON U.S. contends that its generation and transmission functions 

 372 Citing Order No. 890 at P 1682 (citing Order No. 888-A at 30,286 and 30,366). 

373 Citing Southwest Power Pool, 112 FERC ¶ 61,355 at P 23-24 (2005). 
Docket No. RM05-17-001, et al. - 527 -

are not Affiliates because they are part of the same corporate entity. E.ON U.S. asks the 

Commission to clarify whether it intends to include a transmission provider’s unbundled 

generation function within the definition of Affiliate even if the generation function is 

part of the same corporate entity. 

Commission Determination

1003. The Commission grants rehearing, as requested by EEI, to amend the pro forma

OATT such that every use of the term Affiliate is capitalized. We agree with APPA that 

members of an umbrella joint action agency are not Affiliates of the joint action agency 

within the meaning of the pro forma OATT. We clarify in response to E.ON U.S., 

however, that the transmission function and generation function of a single corporation 

are Affiliates. Each would be an entity under common control, notwithstanding the fact 

that they are within the same corporation. 

b. Good Utility Practice

1004. In Order No. 890, the Commission incorporated the definition of reliable operation 

in FPA section 215 into the definition of Good Utility Practice in the pro forma OATT. 

As amended, the definition of Good Utility Practice is: “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 
Docket No. RM05-17-001, et al. - 528 -

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).”

Requests for Rehearing and Clarification

1005. Xcel argues that revising the definition of Good Utility Practice to include 

compliance with the mandatory reliability standards of FPA section 215 inappropriately 

subjects transmission providers to two separate enforcement schemes for alleged 

violations of the reliability standards. Xcel suggests that the Commission eliminate from 

the definition of Good Utility Practice the reference to practices under FPA section 215. 

Xcel argues that this would not eliminate the obligation of transmission providers or 

transmission owners to comply with the mandatory reliability standards and, instead, 

would make such compliance subject to enforcement and potential penalties under one 

enforcement regime, as contemplated by Congress under the FPA. 

1006. If the Commission does not eliminate the reference to practices required by section 

215, Xcel asks the Commission to clarify that reliability standards that have not been 

approved under FPA section 215 would not be enforceable as an OATT violation.374 

Xcel also argues that a violation of a mandatory reliability standard approved by the 

Commission should be subject to enforcement only by the ERO or applicable RE under 

the compliance and enforcement scheme created by NERC and the Commission under 

FPA section 215. Xcel contends it would subject FERC-jurisdictional transmission 

 374 Citing Order No. 693 at P 302. 
Docket No. RM05-17-001, et al. - 529 -

providers to “double jeopardy” to allow a claim of an alleged violation of a mandatory 

reliability standard to be pursued in both an OATT enforcement proceeding and a section 

215 enforcement proceeding. Finally, Xcel argues that in no event should an alleged 

violation of a mandatory reliability standard be subject to dual financial penalties through 

separate enforcement actions by the Commission for an OATT violation and by the ERO 

or RE for a reliability violation. 

Commission Determination

1007. The Commission affirms the decision in Order No. 890 to incorporate within the 

definition of Good Utility Practice those practices required by FPA section 215(a)(4). 

Even without the revisions adopted in Order No. 890, the definition of Good Utility 

Practice would have incorporated each reliability standard approved by the Commission, 

since they represent practices in which the industry is required to engage. The 

Commission simply made this explicit in Order No. 890. 

1008. As we explained in Order No. 693, however, the Commission does not believe it 

would be appropriate to retain a dual mechanism to enforce reliability standards both as 

Good Utility Practice and under FPA section 215.375 The pro forma OATT only applies 

to entities subject to our jurisdiction as public utilities under the FPA, while section 215 

defines more broadly our jurisdiction with respect to mandatory reliability standards. We 

therefore do not intend to enforce, as an OATT violation, compliance with any reliability 

standard approved by the Commission under section 215. It is more appropriate for the 

 375 See id. 
Docket No. RM05-17-001, et al. - 530 -

Commission to rely on its authority under section 215 to enforce compliance with 

mandatory reliability standards. 

c. Non-Firm Sales 

1009. In order to clarify the obligations of network customers under section 30.4 of the 

pro forma OATT, the Commission adopted the following definition of Non-Firm Sales in 

the pro forma OATT: “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.” 

Requests for Rehearing and Clarification

1010. NRECA asks the Commission to clarify that a unit-contingent contract is not a 

Non-Firm Sale within the meaning of the pro forma OATT, which NRECA argues would 

make it ineligible for designation as a network resource. NRECA states that unitcontingent contracts excuse non-delivery only on account of constraints on the unit 

providing service and not, more generally, for “any reason” or “no reason.” NRECA 

contends that such contracts are sufficiently firm to be considered “LU” and “IU” service 

in FERC Form One Account 447 and should likewise not be considered Non-Firm Sales 

under the pro forma OATT. 

1011. Southern questions whether system-firm sales that permit curtailment without 

penalty to serve the seller’s native load should be treated as Non-Firm Sales for purposes 

of section 30.4 of the pro forma OATT. Southern states that the Commission has 

considered the purchase of a system-firm energy to be eligible for designation as a 
Docket No. RM05-17-001, et al. - 531 -

network resource,376 but contends that it is ambiguous whether the seller should consider 

those sales as a Non-Firm Sale. Southern argues that treating such sales as Non-Firm 

Sales would assure internal consistency within the pro forma OATT, foster liquidity in 

short-term wholesale opportunity markets, and promote the efficient optimization of 

network resources. 

1012. Washington IOUs argues that a contract that allows for interruption to serve native 

load should be considered a Non-Firm Sale even if there is a “make whole” penalty for 

the interruption. Washington IOUs argue that a requirement that sales from a designated 

network resource be recallable for service of native or network load without any financial 

consequences would constitute an unnecessary regulatory intrusion into wholesale 

electricity markets, and is not necessary for reliability purposes.377 

1013. TAPS express similar concerns, asking the Commission to clarify that the 

definition of Non-Firm Sales includes transactions that permit interruption for any or no 

reason without penalty, even if the seller may entail some financial liability for 

interruption. TAPS states that failure to deliver energy sold in a day-ahead organized 

market creates an obligation to pay the real-time LMP and potentially other charges, even 

though the power sale is not generally considered firm. If this potential obligation is 

 376 Citing WPPI. 

377 Washington IOUs argue that, now that the Commission has enforcement 

authority for reliability under section 215 of the FPA, there are avenues to address 

reliability concerns that are more effective than the use of rules for designated network 

resources. 
Docket No. RM05-17-001, et al. - 532 -

interpreted as a liability for purposes of qualifying as a Non-Firm Sale, TAPS concludes 

that sales into day-ahead organized markets cannot be made from a network resource 

without first undesignating that resource, which TAPS argues would be unduly 

burdensome and would discourage network customers from making sales into those 

markets. TAPS contends that network customers will be reluctant to undesignate their 

network resources for fear that they would be unable to redesignate them in a timely 

manner if they are needed to serve native load in real-time. 

1014. With regard to the MISO market in particular, TAPS argues that refusing to treat 

sales into that day-ahead market as Non-Firm Sales would require network customers to 

undesignate resources to comply with MISO’s must offer requirements. TAPS argues 

that it would be inappropriate to require undesignation of a network resource to sell into 

the RTO in which the resource is located as well as neighboring RTOs, such as from 

MISO into PJM. The use of centralized dispatch in these markets, TAPS argues, 

eliminates any effect temporary resource undesignations and redesignations may have on 

dispatch or ATC calculations. TAPS contends that the added burden of undesignating 

and redesignating network resources is therefore pointless in centrally dispatched 

markets. 

1015. E.ON LSE expresses similar concerns, arguing that the definition of Non-Firm 

Sale in combination with restricted network resource designation policies will result in 

fewer resources being made available. With regard to the MISO market in particular, 

E.ON LSE states that the MISO tariff requires that certain day-ahead transactions are 

made on the condition that the selling generator provide service on-demand. E.ON LSE 
Docket No. RM05-17-001, et al. - 533 -

similarly request that the Commission clarify that day-ahead and real-time sales in MISO 

and other RTO/ISO markets need not meet the definition of Non-Firm Sales. 

Commission Determination

1016. The Commission agrees with NRECA that, under normal circumstances, we 

would not expect a unit contingent agreement to fall within the definition of a Non-Firm 

Sale since typically delivery can only be interrupted for the specific reasons identified in 

the underlying agreement. We also agree with Southern that, under normal 

circumstances, a system sale that permits curtailment without penalty to serve the seller’s 

native load would fall within the definition of a Non-Firm Sale since the seller would 

have the right to rely on that capacity in the event it is needed to serve native load, which 

is the Commission’s principal concern in restricting sales from designated network 

resources to Non-Firm Sales. Whether any particular contract satisfies the definition of 

Non-Firm Sales, however, must be considered based on the terms and conditions of that 

contract. 

1017. We disagree with TAPS and Washington IOUs that the definition of Non-Firm 

Sales includes transactions that permit interruption with financial liability, whether make 

whole or limited to certain penalties. In Order No. 890, the Commission clarified its 

existing policy prohibiting network customers from making third-party sales from a 

designated network resource if the third-party power purchase agreement does not allow 

the seller to interrupt power sales to the third party in order to serve the designated 
Docket No. RM05-17-001, et al. - 534 -

network load.378 The Commission adopted the definition of Non-Firm Sales to identify 

more clearly those types of sales that are permitted from designated network resources, 

explaining that any interruption in service that would create liability on the part of the 

seller would create conflicting incentives regarding use of the network resource and, 

therefore, such sale could not be made without first undesignating the resource.379 The 

Commission concluded that it would be inappropriate to adopt commenter suggestions to 

relax the definition of a Non-Firm Sale to include any sale that is not otherwise firm 

enough to be designated as a network resource.380

1018. We appreciate the concerns of E.ON LSE and TAPS regarding the potential effect 

of this decision on RTO/ISO markets. It does not follow, however, that the pro forma

OATT must be amended to accommodate the particular market operations of each RTO 

and ISO. RTOs and ISOs have adopted many variations from the pro forma OATT to 

facilitate development of their markets, with some entirely eliminating the 

designation/undesignation requirements for network resources. As TAPS explains, 

centralized dispatch in these markets may very well eliminate any effect that temporary 

resource undesignations and redesignations have on dispatch or ATC calculations and, 

 378 See Order No. 890 at P 1539. 

379 See id. at P 1692. The Commission’s use of the word “penalty” in paragraph 

1539 of Order No. 890 was not intended to restrict the scope of Non-Firm Sales. As the 

Commission explained in that paragraph, our concern is that there not be financial 

incentives that compete with the network resource’s obligations to serve its network load. 

Interruption must therefore be allowed without liability or penalty. 

380 Id.
Docket No. RM05-17-001, et al. - 535 -

therefore, tailoring the rules governing the designation of network resources to each 

RTO/ISO market could be appropriate. 

1019. We note that MISO has adopted the pro forma definition of Non-Firm Sales in its 

compliance filing in response to Order No. 890 and certain members of TAPS have 

argued in response that adoption of that definition is inconsistent with the operation of the 

MISO market.381 The Commission will address those arguments on review of the MISO 

compliance filing. In the interim, we note that MISO retains significant discretion in how 

to implement the undesignation requirements for network resources. Pending 

development of OASIS functionality for electronic submission of undesignations and 

redesignations, each transmission provider may adopt business practices governing the 

undesignation and redesignation of network resources. While the Commission 

referenced the use of telefax or recorded telephone lines to convey this information,382 the 

bid-based nature of LMP markets may justify adoption of other procedures. We decline 

to impose any particular requirements here regarding the designation and undesignation 

of network resources selling in an RTO/ISO market, as it is more appropriate to leave 

development of those requirements to each transmission provider, in coordination with its 

stakeholders as relevant. 

 381 See Supplemental Comments of Indiana Municipal Power Agency, Lincoln 

Electric System, Madison Gas & Electric Company, and Wisconsin Public Power Inc., 

Docket No. OA08-14-000 (Nov. 6, 2007). 

382 See Order No. 890 at P 1543. 
Docket No. RM05-17-001, et al. - 536 -

d. Commenter Proposals

1020. The Commission declined to adopt various commenter proposals for modifications 

or additions to the definitions contained in the pro forma OATT. For example, the 

Commission declined to revise the definition of Long-Term Firm Point-to-Point 

Transmission Service to include service longer than one year, instead of one year or 

longer. The Commission also rejected commenter requests to adopt proposed definitions 

for the terms “source,” “sink,” “use,” and “transmission peak” in the pro forma OATT.383

Requests for Rehearing and Clarification

1021. Ameren argues that the Commission failed to adequately consider its proposal to 

amend the definition of long-term firm service to include only contracts that are longer 

than a year. Ameren argues that contracts of only one year in duration should be 

reflected as a revenue credit and that the current definition of long-term service makes 

calculation very difficult in the modern RTO/Seams Elimination Cost Allocation 

(SECA) environment. Ameren contends that the Commission’s refusal to modify the 

definition of long-term service is inconsistent with other decisions in Order No. 890, such 

as the requirement that the planning redispatch and conditional firm options for long-term 

firm point-to-point service apply be offered only to customers requesting service of more 

 383 Powerex’s request for rehearing of the Commission’s decision not to modify 

the definition of System Impact Study to exclude short-term service requests is discussed 

in section III.D.4.a.(6) above. 
Docket No. RM05-17-001, et al. - 537 -

than a year in duration384 and the intended planning benefits associated with granting 

rollover rights only to customers with contracts of five years or longer. 

1022. Ameren also challenges the Commission’s rejection of an alternative definition for 

“transmission peak,” arguing that the current definition and calculation methodology is 

unworkable because the data necessary no longer resides with the transmission owner. 

Ameren further states that the Commission failed to adequately explain rejection of 

proposed definitions of “source” and “sink” in section 22.2 of the pro forma OATT, and 

clarification whether the word “use” in section 30.8 of the pro forma OATT includes load 

ratio limitations, although Ameren states no arguments in support of that contention. 

Commission Determination

1023. The Commission affirms the decision in Order No. 890 to maintain the current 

definition of Long-Term Firm Point-to-Point Service. The definition is well-established 

in Commission precedent and, notwithstanding Ameren’s arguments to the contrary, 

consistent with the reforms adopted in Order No. 890.385 Ameren has failed to justify 

altering the definition of Long-Term Firm Point-to-Point Service in light of the disruption 

such a change would cause. 

1024. We also decline to amend the pro forma OATT to adopt Ameren’s proposed 

definitions of “transmission peak,” “source,” “sink,” and “use.” Ameren simply repeats 

 384 Citing Order No. 890 at P 978. 

385 The Commission clarifies in section III.D.1 our intent that the conditional firm 

and planning redispatch options apply to all long-term firm point-to-point requests for 

service, i.e., service of one year or longer. 
Docket No. RM05-17-001, et al. - 538 -

arguments that have previously been rejected. While peak load data ultimately resides 

with the RTO or ISO in those regions, each transmission owner coordinates this data with 

the RTO/ISO and, therefore, it is not necessary to alter the definition of transmission peak 

as suggested by Ameren. The Commission has adequately addressed the definitions of 

“source” and “sink” in Order No. 888 and OASIS related proceedings and Ameren fails 

to state why, in its view, additional clarification is needed. Finally, the Commission has 

made clear that there are no load ratio limitations on the use of interfaces under section 

30.8 of the pro forma OATT.386

E. Enforcement

1025. The Commission addressed several matters regarding enforcement of the pro 

forma OATT in Order No. 890. Among other things, the Commission concluded that it 

would revoke an entity’s market-based rate authority in response to an OATT violation 

only upon a finding of a specific factual nexus between the violation and the entity’s 

market-based rate authority.387 The Commission reasoned that the “nexus condition” is 

required in order to ensure that the Commission’s actions are not arbitrary or capricious 

or based on an inadequate factual record. The Commission noted that in such situations it 

would have the burden to show a factual nexus and did not assign a burden on the 

violator to show a lack of nexus. 

 386 See Order No. 888 at 31,753-54; Order No. 888-A at 30,304-5; see also Sierra 

Pacific Power Co., 81 FERC ¶ 61,136 at 61,139-40 (1997); New England Power Pool, 

83 FERC ¶ 61,045 at 61,248 (1998). 

387 Order No. 890 at P 1743. 
Docket No. RM05-17-001, et al. - 539 -

1026. The Commission disagreed that a finding of a “serious” or “material” violation of 

the OATT alone would be sufficient to justify revocation of an entity’s market-based rate 

authority. The Commission concluded that the nexus condition requires a finding both 

that a substantial OATT violation has occurred and that the violation either related to the 

exercise of the violator’s market-based rate authority or violated a specific condition of 

that authority.388 The Commission emphasized, moreover, that it has discretion to 

fashion further sanctions, such as civil penalties or modification of a violator’s marketbased rate authority, for OATT violations that relate to the violator’s market-based rate 

authority where a factual nexus justification was not found to justify revocation of that 

authority. 

1027. The Commission also created a rebuttable presumption that all of the transmission 

provider’s affiliates should lose their market-based rate authority in each market in which 

their affiliated transmission provider loses its market-based rate authority as a result of an 

OATT violation.389 The Commission stated that it would allow an affiliate of a 

transmission provider to retain its market-based rate authority in a market area if the 

affiliate overcomes the rebuttable presumption with respect to that market area. To 

afford due process to a transmission provider’s affiliates and to ensure that revocation of 

market-based rate authority in a particular market for the transmission provider and all of 

its affiliates is adequately based upon record evidence and not arbitrary or capricious, the 

 388 Id. at P 1744. 

389 Id. at P 1747. 
Docket No. RM05-17-001, et al. - 540 -

Commission provided that each such affiliate will be allowed to make a showing that it 

should retain its market-based rate authority or that enforcement action against it should 

be less severe than revocation. 

1028. The Commission explained that whether an affiliate has overcome the rebuttable 

presumption will depend on an analysis of specific facts in the record. Relevant facts 

would include, but are not limited to, whether: (1) the transmission provider and the 

affiliate were under the same control; (2) the affiliate knew of, participated in or was an 

accomplice to the OATT violation; (3) the affiliate assisted the transmission provider in 

exercising market power; or (4) the affiliate benefited from the violation.390

Requests for Rehearing and Clarification 

1029. NRECA argues that it is unclear what would constitute a sufficient factual nexus 

between an OATT violation and revocation of the violator’s market-based rate authority. 

NRECA suggests that the Commission instead adopt the standard advocated by APPA in 

its NOPR comments, which would require revocation of the affiliate’s market-based rate 

authority when there is any material violation of the transmission provider’s OATT that 

denies a customer access to just, reasonable, nondiscriminatory, and comparable 

transmission service. If the Commission retains the nexus requirement as formulated in 

Order No. 890, NRECA asks that the Commission provide an illustrative list of what 

types of violations could constitute a sufficient nexus between an OATT violation and an 

entity’s market-based rate authority. NRECA urges the Commission to specifically 

 390 Id. at P 1748. 
Docket No. RM05-17-001, et al. - 541 -

identify failure to comply with the planning requirements of Order No. 890 as satisfying 

the nexus requirement. 

1030. TDU Systems argue that the nexus requirement does not pay adequate attention to 

the basic nature and purpose of the market-based rate authorization and, in their view, the 

critical question is whether the OATT violation is indicative of conditions in the market 

which are significantly different from those upon which the market-based rate 

authorization was premised. TDU Systems argue that a transmission provider’s violation 

of a material term of its OATT should serve as prima facie evidence that the structures 

presumed to cabin the exercise of monopoly power may not be adequate. Even if the 

transmission provider has not violated its OATT explicitly in connection with the marketbased rate authorization, TDU Systems contend that the violation may nonetheless 

promote conditions in which the transmission provider could gain an advantage in future 

transactions. TDU Systems state particular concern that failure to comply with the 

planning obligations of Order No. 890 may not be associated with any specific exercise 

of market-based rate authority, yet could foster conditions inconsistent with the premises 

of unconstrained and competitive markets. 

1031. EEI argues that, since there is no rebuttable presumption with respect to a 

transmission provider’s OATT violation and its potential loss of market-based rate 

authority, there should be no rebuttable presumption regarding the market-based rate 

authority of the transmission provider’s affiliates. EEI contends that the Commission’s 

Code of Conduct actually supports a presumption that a transmission provider’s OATT 

violation does not have any relation to the activities of the marketing affiliate since, 
Docket No. RM05-17-001, et al. - 542 -

absent evidence to the contrary, the utility and its energy affiliates should be presumed to 

be obeying the Commission’s separation of function requirements. EEI further argues 

that the Commission’s reference to allegations that transmission providers have engaged 

in transactions with affiliates does not justify adoption of a rebuttable presumption in 

instances in which there are no transactions with affiliates that violated the OATT. EEI 

therefore asks the Commission to grant rehearing and hold that the rebuttable 

presumption applies only if there is a specific factual nexus between the activities of the 

marketing affiliate and the OATT violation. 

1032. Ameren similarly argues that most integrated utility companies that have marketbased rate authority have separated their marketing activities into “regulated” traditional 

utility functions and “non-regulated” power marketing functions and have further 

separated their transmission and merchant energy functions. Ameren states that these 

utilities’ codes of conduct and the Commission’s Standards of Conduct severely restrict 

the sharing of information within an integrated utility company or the possible benefit to 

affiliates from an OATT violation. Ameren argues that the presumption adopted by the 

Commission unreasonably assumes a lack of compliance with these obligations and 

unfairly shifts the burden to the affiliate to show that it has not engaged in bad acts. 

1033. Ameren contends that a decision by the Commission to revoke a transmission 

provider’s market-based rate authority would indicate only that the Commission has 

determined that sanction to be appropriate in light of the transmission provider’s actions. 

In Ameren’s view, there is no reason or basis to similarly sanction the transmission 

provider’s affiliate in the absence of a showing that the affiliate participated in, or 
Docket No. RM05-17-001, et al. - 543 -

benefited from, the transmission provider’s improper behavior. Ameren also argues that 

the presumption is inconsistent with the Commission’s decision in Order No. 890 to 

allow non-offending affiliates of the transmission provider to share in the distribution of 

operating penalties. Finally, Ameren argues that revoking the market-based rate 

authority of a utility because of the actions of an affiliated transmission provider would 

unfairly harm the traditional utility affiliate as well as its bundled customers since many 

traditional utilities engage in sales at market-based rates to reduce their overall cost of 

power. 

1034. Southern asks that the Commission confirm and clarify that the rebuttable 

presumption does not shift the ultimate burden of proof to the transmission provider or its 

affiliates, but rather places a burden of going forward on the affiliates, with the ultimate 

burden remaining with the Commission or other proponents of a revocation sanction. 

Southern suggests that the presentation of evidence that rebuts the presumption should 

result in the burden of proof reverting back to the Commission or the proponent of 

revocation. 

1035. Southern also requests clarification of the relevant facts to be considered by the 

Commission in determining whether a sanction less severe than revocation of marketbased rate authority may be appropriate for an affiliate. Southern notes that the first 

relevant fact noted by the Commission in paragraph 1748 of Order No. 890 is whether the 

transmission provider and the affiliate were under “the same control.” Southern 

questions what the Commission meant by that language since a transmission provider is 

by definition under the same corporate control as an affiliate. 
Docket No. RM05-17-001, et al. - 544 -

Commission Determination

1036. The Commission denies rehearing of the decision in Order No. 890 to require a 

factual nexus between a substantial OATT violation and the entity’s market-based rate 

authority to justify revocation of that authority. As the Commission explained in Order 

No. 890, the “nexus condition” is required in order to ensure that our actions are not 

arbitrary or capricious or based on an inadequate factual record. We disagree with 

NRECA and TDU Systems that any material OATT violation should justify revocation of 

the entity’s market-based rate authority since the violation may have no relation to the 

market-based rate authority. In such circumstances, the Commission will consider such 

other sanctions as may be appropriate. We also decline to provide an illustrative list of 

examples that would constitute a sufficient nexus between an entity’s market-based rate 

authority and an OATT violation. The factual circumstances involved in a claimed 

violation will be unique to the company and, therefore, any such list would be 

incomplete. This is especially true in light of continually developing market conditions. 

We continue to believe that the determination of what would be a sufficient factual nexus 

between an OATT violation and revocation of the violator’s market-based rate authority 

is best left to case-by-case consideration. 

1037. With regard to the transmission provider’s planning obligations, violations of the 

planning-related requirements of the pro forma OATT may or may not have a sufficient 

factual nexus with the transmission provider’s market-based rate authority. A case-bycase analysis will be necessary to determine if the violation justifies revocation of the 

transmission provider’s market-based rate authority. While we agree with TDU Systems 
Docket No. RM05-17-001, et al. - 545 -

that a transmission provider’s OATT violations that are not explicitly connected with its 

market-based rate authorization may nonetheless promote conditions in which the 

violator could gain an advantage in future transactions, we note that this is the precise 

result that we seek to avoid with this enforcement provision. Therefore, we will apply 

the mechanisms adopted in Order No. 890 to aid us in determining, on a case-by-case, 

basis if a particular violation promotes conditions that will put that company at a future 

advantage vis-à-vis its market-based rate authority. 

1038. We also decline to adopt TDU Systems’ suggestion that we consider whether the 

OATT violation is indicative of conditions in the market that are significantly different 

from those upon which the market-based rate authorization was premised. When the 

revocation of market-based rate authority is being considered, we will distinguish 

between those violations resulting from a change in market conditions upon which the 

market-based rate authority was granted (and which are likely outside of the company’s 

control) versus a clear violation related to the company’s market-based rate authority. It 

may be most appropriate to address those violations resulting from changes in market 

conditions with an amendment to the affected company’s OATT or market-based rate 

tariff. 

1039. We also affirm the adoption of a rebuttable presumption that all of the 

transmission provider’s affiliates should lose their market-based rate authority in each 

market in which their affiliated transmission provider loses its market-based rate 
Docket No. RM05-17-001, et al. - 546 -

authority as a result of an OATT violation.391 While we agree that, absent evidence to the 

contrary, the transmission provider and its affiliates should be presumed to be obeying 

the Commission’s separation of function requirements and Affiliate Restrictions, we 

disagree that this undermines the rebuttable presumption adopted in Order No. 890. If a 

violation has occurred that justifies revocation of the entity’s market-based rate authority, 

the violation must have related to that market-based rate authority. Assuming that the 

Standards of Conduct and Affiliate Restrictions were followed, the finding of a nexus 

between the violation and the entity’s market-based rate authority demonstrates that the 

Standards of Conduct or Affiliate Restrictions did not preclude the violation. An OATT 

violation by a transmission provider that merits revocation of the transmission provider’s 

market-based rate authority will, at a minimum, raise the question whether the 

transmission provider’s affiliates continue to qualify for market-based rates under the 

standards established by the Commission. 

1040. Applying this rebuttable presumption to the transmission provider’s affiliates is 

not, as suggested by Ameren, inconsistent with the Commission’s decision in Order No. 

890 to allow non-offending affiliates of the transmission provider to share in the 

distribution of unreserved use penalties.392 Unreserved use penalties are a mechanism 

used to redress administrative violations of the OATT and can be assessed on any 

 391 Accord Order No. 697 at P 424-427. 

392 Although Ameren refers more generally to operational penalties, only 

unreserved use penalties may be distributed to affiliated customers. Late study penalties 

are to be distributed only to non-affiliated transmission customers. See Order No. 890 at 

P 1351. 
Docket No. RM05-17-001, et al. - 547 -

transmission customer. It is therefore appropriate to distribute those penalties to all nonoffending customers, whether or not affiliated with the transmission provider. 

Unreserved use penalties do not rise to the level of the sanction of revocation of marketbased rate authority, to which the presumption applies. 

1041. We also disagree that there must be a showing of benefit by the affiliate in order to 

revoke its market-based rate authority or that potential economic harm to the transmission 

provider’s bundled customers categorically justifies an affiliate to continue making sales 

at market-based rates to reduce the company’s overall cost of power, even if the affiliate 

should otherwise lose its market-based rate authority. It is possible that a transmission 

provider could violate its OATT with an intent to advantage an affiliated marketer that, in 

turn, attempts to take advantage of the violation in the market but is unsuccessful because 

of market conditions. Alternatively, the affiliated marketer could be successful, gaining 

an unfair advantage due to the transmission provider’s OATT violation, but thereby 

earning revenue that ultimately serves to lower the cost of supplies for the company’s 

bundled customers. In either of these circumstances, it could be appropriate to revoke or 

modify the market-based rate authority of the affiliate. Therefore, the facts of each 

violation must be considered in order to determine if revocation of market-based rate 

authority is an appropriate sanction. 

1042. With regard to Southern’s request for clarification concerning the burden of proof 

to show that an affiliate should lose its market-based rate authority, we confirm that the 

ultimate burden remains with the Commission. The presumption does not constitute a 

definitive finding that the affiliate’s market-based rate authority should be revoked and, 
Docket No. RM05-17-001, et al. - 548 -

thus, the affiliate has an opportunity to demonstrate that revocation would not be 

appropriate under the facts and circumstances at issue.393 The rebuttable presumption 

thus satisfies the Commission’s burden of going forward and shifts to the affiliate the 

burden of presenting evidence rebutting the presumption. The ultimate burden of proof 

remains with the Commission throughout these proceedings, and it must base any finding 

on a review of the factual record.394

1043. We clarify in response to Southern that the reference to whether “the transmission 

provider and the affiliate were under the same control” in paragraph 1748 of Order No. 

890 is intended to reflect that the Commission will consider whether the affiliation 

between the transmission provider and the affiliate is sufficient to give either or a 

common parent control over both entities. 

IV. Information Collection Statement

1044. The Office of Management and Budget (OMB) regulations require that OMB 

approve certain information collection requirements imposed by an agency.395 The 

revisions to the information collection requirements for transmission providers adopted in 

Order No. 890 were approved under OMB Control Nos. 1902-0233. This order further 

revises these requirements in order to more clearly state the obligations imposed in Order 

 393 The use of shifting burdens of proof is consistent with Commission practice in 

other areas. See, e.g., AEP Power Mktg, Inc., 108 FERC ¶ 61,026 (2004); Southern 

Companies Energy Mktg, Inc., 111 FERC ¶ 61,144 (2005). 

394 See Order No. 890 at P 1743-48. 

395 5 CFR 1320. 
Docket No. RM05-17-001, et al. - 549 -

No. 890, but does not substantively alter those requirements. OMB approval of this order 

is therefore unnecessary. However, the Commission will send a copy of this order to 

OMB for informational purposes only. 

V. Document Availability

1045. 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 FERC's Home Page 

(http://www.ferc.gov) and in FERC'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. 

1046. From FERC's Home Page on the Internet, this information is available on 

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 the docket number excluding the last three digits of this document in the 

docket number field. 

1047. User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-

8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 
Docket No. RM05-17-001, et al. - 550 -

VI. Effective Date and Congressional Notification

1048. Changes to Order No. 890 adopted in this order on rehearing will become effective 

[insert date 60 days from publication in the Federal Register]. 

List of subjects in 18 CFR Part 37 

Conflict on interests, Electric power rates, Electric power plants, Reporting and 

recordkeeping requirements 

By the Commission. 

( S E A L ) 

 Nathaniel J. Davis, Sr., 

 Deputy Secretary. 
Docket No. RM05-17-001, et al. - 551 -

In consideration of the foregoing, the Commission amends part 37, Chapter I, Title 

18 of the Code of Federal Regulations, as follows: 

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 (b)(3)(iv) is revised. 

b. Paragraph (h)(1) is revised. 

c. Paragraph (h)(3) is revised. 

d. Paragraphs (i) is revised. 

§ 37.6 Information to be posted on the OASIS. 

(b) * * * 

 (3) * * * 

 (iv) Daily load. The Transmission Provider must post on a daily basis, its load 

forecast, including underlying assumptions, and actual daily peak load for the prior day. 

* * * * * 

(h) Posting information summarizing the time to complete transmission service 

request studies. (1) For each calendar quarter, the Responsible Party must post the set of 

measures detailed in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section 

related to the Responsible Party’s processing of transmission service request system 

impact studies and facilities studies. The Responsible Party must calculate and post the 
Docket No. RM05-17-001, et al. - 552 -

measures in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section for requests 

for short-term firm point-to-point transmission service, requests for long-term firm pointto-point transmission service, and requests to designate a new network resource or 

network load. When calculating the measures in paragraph (h)(l)(i) through paragraph 

(h)(l)(iv) of this section, the Responsible Party may aggregate requests for short-term 

firm point-to-point service and requests for long-term firm point-to-point service, but 

must calculate and post measures 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. 

(2) * * * 

(3) The Responsible Party will be required to post on OASIS the measures in 

paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section in the event the 

Responsible Party, for two consecutive calendar quarters, completes more than twenty 

(20) percent of the studies associated with requests for transmission service from entities 

that are not Affiliates of the Responsible Party more than sixty (60) days after the 

Responsible Party delivers the appropriate study agreement. The Responsible Party will 

have to post the measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this 

section until it processes at least ninety (90) percent of all studies within 60 days after it 

has received the appropriate executed study agreement. For the purposes of calculating 
Docket No. RM05-17-001, et al. - 553 -

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. 

* * * * * 

(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, including 

requests by the transmission provider’s merchant function to designate a network resource 

or to procure secondary network service, that have been rejected, and 

(4) The total number of Affiliate requests for transmission service, including 

requests by the transmission provider’s merchant function to designate, or terminate the 

designation of, a network resource or to procure secondary network service, that have 

been made. 
Docket No. RM05-17-001, et al. - 554 -

Appendix A: Petitioner Acronyms

Abbreviation Petitioner Names 

Alcoa Alcoa Inc. and Alcoa Power Generating Inc. 

Ameren Ameren Services Company 

AMP-Ohio American Municipal Power-Ohio, Inc. 

APPA American Public Power Association 

AWEA American Wind Energy Association 

Areva Areva T&D 

APS Arizona Public Service Company 

ATCLLC American Transmission Company LLC 

Barclays Barclays Bank PLC, Credit Suisse Energy LLC, J. Aron 

& Co., and Morgan Stanley Capital Group Inc. 

Bonneville Bonneville Power Administration 

Constellation Constellation Energy Group, Inc. 

Duke Duke Energy Corp. 

Dynegy Dynegy Power Marketing, Inc., Entegra Power Group 

LLC, LS Power Associates 

E.ON LSE E.ON Load Serving Entity 

E.ON U.S. E.ON U.S. LLC 
Docket No. RM05-17-001, et al. - 555 -

Abbreviation Petitioner Names 

East Texas Cooperatives 

East Texas Electric Cooperative, Inc.; Northeast Texas 

Electric Cooperative, Inc.; Sam Rayburn Generation and 

Electric Cooperative, Inc. and Tex-La Electric 

Cooperative of Texas, Inc. 

EEI Edison Electric Institute 

EPSA Electric Power Supply Association 

Entergy Entergy Services, Inc. 

Financial Service Joint 

Requestors 

Barclays Bank PLC, Credit Suisse Energy LLC, J. Aron 

& Company, and Morgan Stanley Capital Group Inc. 

FMPA Florida Municipal Power Agency and Midwest 

Municipal Transmission Group 

Florida Power Florida Power & Light Co. 

Great Northern Great Northern Power Development, L.P. 

Idaho Power Idaho Power Co. 

Indicated Commenters Dynegy Power Marketing, Inc., Entegra Power Group 

LLC, and LS Power Associates, L.P. 

ISO/RTO Council ISO/RTO Council 

Mark Lively Mark B. Lively 

MidAmerican MidAmerican Energy Company and PacifiCorp 

MISO Midwest Independent Transmission System Operator, 

Inc. 

Morgan Stanley Morgan Stanley Capital Group Inc. 

National Grid National Grid USA 
Docket No. RM05-17-001, et al. - 556 -

Abbreviation Petitioner Names 

NRECA National Rural Electric Cooperative Association 

NYISO New York Independent System Operator 

New York Transmission 

Owners 

Central Hudson Gas & Elec. Corp., Consolidated Edison 

Co. of New York, Inc., LIPA, New York Power 

Authority, New York State Electric & Gas Corp., Orange 

and Rockland Utilities, Inc., and Rochester Gas and 

Electric Corp. 

NCEMC North Carolina Electric Membership Corporation 

NCPA Northern California Power Agency 

NorthWestern NorthWestern Corporation 

Old Dominion Old Dominion Electric Cooperative 

Pacific Northwest Parties 

Avista Corp., Bonneville Power Administration, 

PacifiCorp, PNGC Power, Portland General Electric 

Company, and Puget Sound Energy, Inc. 

PJM PJM Interconnection, LLC 

Powerex Powerex Corp. 

Progress Energy 

Progress Energy, Inc. (Carolina Power & Light Co. d/b/a 

Progress Energy Carolinas, Inc. and Florida Power Corp., 

d/b/a Progress Energy Florida, Inc.) 

PNM Public Service Company of New Mexico 

PSEG 

Public Service Electric and Gas Company; PSEG Power 

LLC; and PSEC Energy Resources & Trade LLC (PSEG 

Companies) 
Docket No. RM05-17-001, et al. - 557 -

Abbreviation Petitioner Names 

REPIO 

Renewable Energy and Public Interest Organizations 

(The Project for Sustainable FERC Energy Policy, 

Environmental Law & Policy Center, Illinois Citizens 

Utility Board, Natural Resources Defense Council, 

Northwest Energy Coalition, Pace Energy Project, 

Renewable Northwest Project, West Wind Wires, and 

Wind on Wires 

Sempra Global Sempra Global 

South Carolina E&G South Carolina Electric & Gas Company 

South Carolina Regulatory 

Staff South Carolina Office of Regulatory Staff 

Southern Southern Company Services, Inc. 

Steel Manufacturers 

Association Steel Manufacturers Association 

Tenaska Tenaska Power Services, Co. 

TranServ TranServ International, Inc. 

TAPS Transmission Access Policy Study Group 

TDU Systems Transmission Dependent Utilities Systems 

Unitil Unitil Power Corp., Unitil Energy Systems, Inc. and 

Fitchburg Gas and Elec. Light Co. 

Washington IOUs Avista Corp. and Puget Sound Energy, Inc. 

Williams Williams Power Company, Inc. 

Wisconsin Electric Wisconsin Electric Power Company 
Docket No. RM05-17-001, et al. - 558 -

Abbreviation Petitioner Names 

WSPP Western Systems Power Pool, Inc. 

Xcel Xcel Energy Services, Inc. 
Docket No. RM05-17-001, et al. - 559 -

Appendix B: Post -Technical Conference Commenter Acronyms 

Abbreviation Commenter Names 

Alabama Municipal Alabama Municipal Electric Authority 

APS and EEI Arizona Public Service Company and Edison Electric 

Institute 

Barrick Goldstrike Mines Barrick Goldstrike Mines Inc. and Barrick Turquoise 

Ridge Inc. 

Bonneville Bonneville Power Administration 

Duke Energy Carolinas Duke Energy Carolinas, LLC 

Duke and EEI Duke Energy Corp. and Edison Electric Institute 

EPSA Electric Power Supply Association 

Great Lakes Great Lakes Utilities 

Hoosier Hoosier Energy Rural Electric Cooperative, Inc. 

Kansas Power Pool Kansas Power Pool 

MISO Midwest Independent Transmission System Operator, 

Inc. 

Morgan Stanley Morgan Stanley Capital Group Inc. 

Pacific Northwest IOUs Avista Corp., Portland General Electric Company, and 

Puget Sound Energy, Inc. 

Powerex Powerex Corp. 

PNGC Power Pacific Northwest Generating Cooperative, Inc. 
Docket No. RM05-17-001, et al. - 560 -

Abbreviation Commenter Names 

PPC Public Power Council 

PPL Parties 

PPL EnergyPlus, LLC, Lower Mount Bethel Energy, 

LLC, PPL Brunner Island, LLC, PPL Edgewood Energy, 

LLC, PPL Great Works, LLC, PPL Holtwood, LLC, PPL 

Maine, LLC, PPL Martins Creek, LLC, PPL Montana, 

LLC, PPL Montour, LLC, PPL Shoreham Energy, LLC, 

PPL Susquehanna, LLC, PPL University Park, LLC, and 

PPL Wallingford Energy LLC. 

Reliant Reliant Energy, Inc. 

SCE and SDG&E Southern California Edison Co. and San Diego Gas & 

Electric Co. 

South Carolina E&G South Carolina Electric & Gas Company 

Southern Southern Company Services, Inc. 

Southwestern Utilities 

Arizona Public Service Company, El Paso Electric 

Company, Nevada Power Company and Sierra-Pacific 

Power Company, Public Service Company of New 

Mexico, Salt River Project, Tucson Electric Power 

Company, and UNS Electric Inc. 

TAPS and APPA Transmission Access Policy Study Group and the 

American Public Power Association 

TDU Systems Transmission Dependent Utilities Systems 

WSPP Western Systems Power Pool, Inc. 
Appendix C

RM05-17-001, -002 & RM05-25-001, -002 

(Issued) 

PRO FORMA OPEN ACCESS 

TRANSMISSION TARIFF 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 2 

TABLE OF CONTENTS 

I. COMMON SERVICE PROVISIONS...................................................................10

1 DEFINITIONS...........................................................................................................10

1.1 Affiliate:.........................................................................................................10

1.2 Ancillary Services: ........................................................................................10

1.3 Annual Transmission Costs:..........................................................................10

1.4 Application: ...................................................................................................10

1.5 Commission:..................................................................................................11

1.6 Completed Application:.................................................................................11

1.7 Control Area: .................................................................................................11

1.8 Curtailment:...................................................................................................12

1.9 Delivering Party:............................................................................................12

1.10 Designated Agent: .........................................................................................12

1.11 Direct Assignment Facilities: ........................................................................12

1.12 Eligible Customer:.........................................................................................12

1.13 Facilities Study: .............................................................................................13

1.14 Firm Point-To-Point Transmission Service:..................................................13

1.15 Good Utility Practice:....................................................................................14

1.16 Interruption:...................................................................................................14

1.17 Load Ratio Share: ..........................................................................................14

1.18 Load Shedding:..............................................................................................15

1.19 Long-Term Firm Point-To-Point Transmission Service: ..............................15

1.20 Native Load Customers: ................................................................................15

1.21 Network Customer:........................................................................................15

1.22 Network Integration Transmission Service:..................................................16

1.23 Network Load:...............................................................................................16

1.24 Network Operating Agreement: ....................................................................16

1.25 Network Operating Committee: ....................................................................16

1.26 Network Resource: ........................................................................................17

1.27 Network Upgrades:........................................................................................17

1.28 Non-Firm Point-To-Point Transmission Service: .........................................17

1.29 Non-Firm Sale: ..............................................................................................18

1.30 Open Access Same-Time Information System (OASIS): .............................18

1.31 Part I: .............................................................................................................18

1.32 Part II: ............................................................................................................18

1.33 Part III:...........................................................................................................19

1.34 Parties: ...........................................................................................................19

1.35 Point(s) of Delivery: ......................................................................................19
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 3 

1.36 Point(s) of Receipt:........................................................................................19

1.37 Point-To-Point Transmission Service: ..........................................................20

1.38 Power Purchaser: ...........................................................................................20

1.39 Pre-Confirmed Application: ..........................................................................20

1.40 Receiving Party: ............................................................................................20

1.41 Regional Transmission Group (RTG): ..........................................................20

1.42 Reserved Capacity:........................................................................................21

1.43 Service Agreement: .......................................................................................21

1.44 Service Commencement Date: ......................................................................21

1.45 Short-Term Firm Point-To-Point Transmission Service:..............................21

1.46 System Condition: .........................................................................................22

1.47 System Impact Study:....................................................................................22

1.48 Third-Party Sale:............................................................................................22

1.49 Transmission Customer:................................................................................22

1.50 Transmission Provider:..................................................................................23

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..............................................24

2.1 Initial Allocation of Available Transfer Capability: .....................................24

2.2 Reservation Priority For Existing Firm Service Customers:.........................24

3 ANCILLARY SERVICES ...........................................................................................26

3.1 Scheduling, System Control and Dispatch Service:......................................29

3.2 Reactive Supply and Voltage Control from Generation or Other Sources 

Service: ......................................................................................................................29

3.3 Regulation and Frequency Response Service: ..............................................29

3.4 Energy Imbalance Service:............................................................................29

3.5 Operating Reserve - Spinning Reserve Service: ...........................................29

3.6 Operating Reserve - Supplemental Reserve Service:....................................29

3.7 Generator Imbalance Service: .......................................................................30

4 OPEN ACCESS SAME-TIME INFORMATION SYSTEM (OASIS)................................30

5 LOCAL FURNISHING BONDS...................................................................................31

5.1 Transmission Providers That Own Facilities Financed by Local Furnishing 

Bonds: .......................................................................................................................31

5.2 Alternative Procedures for Requesting Transmission Service:.....................31

6 RECIPROCITY..........................................................................................................33

7 BILLING AND PAYMENT .........................................................................................34
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 4 

7.1 Billing Procedure:..........................................................................................34

7.2 Interest on Unpaid Balances:.........................................................................35

7.3 Customer Default:..........................................................................................35

8 ACCOUNTING FOR THE TRANSMISSION PROVIDER'S USE OF THE TARIFF..............36

8.1 Transmission Revenues:................................................................................36

8.2 Study Costs and Revenues: ...........................................................................36

9 REGULATORY FILINGS ...........................................................................................37

10 FORCE MAJEURE AND INDEMNIFICATION..............................................................37

10.1 Force Majeure:...............................................................................................37

10.2 Indemnification:.............................................................................................38

11 CREDITWORTHINESS ..............................................................................................39

12 DISPUTE RESOLUTION PROCEDURES .....................................................................39

12.1 Internal Dispute Resolution Procedures:.......................................................39

12.2 External Arbitration Procedures:...................................................................39

12.3 Arbitration Decisions:....................................................................................40

12.4 Costs: .............................................................................................................41

12.5 Rights Under The Federal Power Act: ..........................................................41

II. POINT-TO-POINT TRANSMISSION SERVICE...............................................41

13 NATURE OF FIRM POINT-TO-POINT TRANSMISSION SERVICE ...............................42

13.1 Term: .............................................................................................................42

13.2 Reservation Priority:......................................................................................42

13.3 Use of Firm Transmission Service by the Transmission Provider:...............44

13.4 Service Agreements:......................................................................................45

13.5 Transmission Customer Obligations for Facility Additions or Redispatch 

Costs: .......................................................................................................................46

13.6 Curtailment of Firm Transmission Service: ..................................................47

13.7 Classification of Firm Transmission Service: ...............................................49

13.8 Scheduling of Firm Point-To-Point Transmission Service: ..........................51

14 NATURE OF NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE ......................52

14.1 Term: .............................................................................................................52

14.2 Reservation Priority:......................................................................................53

14.3 Use of Non-Firm Point-To-Point Transmission Service by the Transmission 

Provider: ....................................................................................................................54

14.4 Service Agreements:......................................................................................54

14.5 Classification of Non-Firm Point-To-Point Transmission Service:..............55

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service:..................56

14.7 Curtailment or Interruption of Service: .........................................................57
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 5 

15 SERVICE AVAILABILITY.........................................................................................59

15.1 General Conditions:.......................................................................................59

15.2 Determination of Available Transfer Capability:..........................................59

15.3 Initiating Service in the Absence of an Executed Service Agreement:.........59

15.4 Obligation to Provide Transmission Service that Requires Expansion or 

Modification of the Transmission System, Redispatch or Conditional Curtailment:60

15.5 Deferral of Service: .......................................................................................62

15.6 Other Transmission Service Schedules: ........................................................63

15.7 Real Power Losses:........................................................................................63

16 TRANSMISSION CUSTOMER RESPONSIBILITIES ......................................................63

16.1 Conditions Required of Transmission Customers:........................................63

16.2 Transmission Customer Responsibility for Third-Party Arrangements:.......64

17 PROCEDURES FOR ARRANGING FIRM POINT-TO-POINT TRANSMISSION SERVICE 65

17.1 Application: ...................................................................................................65

17.2 Completed Application:.................................................................................66

17.3 Deposit:..........................................................................................................68

17.4 Notice of Deficient Application: ...................................................................69

17.5 Response to a Completed Application: .........................................................70

17.6 Execution of Service Agreement:..................................................................71

17.7 Extensions for Commencement of Service: ..................................................71

18 PROCEDURES FOR ARRANGING NON-FIRM POINT-TO-POINT TRANSMISSION 

SERVICE .........................................................................................................................72

18.1 Application: ...................................................................................................72

18.2 Completed Application:.................................................................................73

18.3 Reservation of Non-Firm Point-To-Point Transmission Service:.................74

18.4 Determination of Available Transfer Capability:..........................................75

19 ADDITIONAL STUDY PROCEDURES FOR FIRM POINT-TO-POINT TRANSMISSION 

SERVICE REQUESTS........................................................................................................75

19.1 Notice of Need for System Impact Study:.....................................................75

19.2 System Impact Study Agreement and Cost Reimbursement: .......................76

19.3 System Impact Study Procedures:.................................................................77

19.4 Facilities Study Procedures: ..........................................................................79

19.5 Facilities Study Modifications:......................................................................81

19.6 Due Diligence in Completing New Facilities:...............................................81

19.7 Partial Interim Service:..................................................................................82

19.8 Expedited Procedures for New Facilities: .....................................................82

19.9 Penalties for Failure to Meet Study Deadlines:.............................................83

20 PROCEDURES IF THE TRANSMISSION PROVIDER IS UNABLE TO COMPLETE NEW 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 6 

TRANSMISSION FACILITIES FOR FIRM POINT-TO-POINT TRANSMISSION SERVICE........85

20.1 Delays in Construction of New Facilities:.....................................................85

20.2 Alternatives to the Original Facility Additions: ............................................86

20.3 Refund Obligation for Unfinished Facility Additions:..................................87

21 PROVISIONS RELATING TO TRANSMISSION CONSTRUCTION AND SERVICES ON THE 

SYSTEMS OF OTHER UTILITIES ......................................................................................87

21.1 Responsibility for Third-Party System Additions:........................................87

21.2 Coordination of Third-Party System Additions: ...........................................88

22 CHANGES IN SERVICE SPECIFICATIONS..................................................................89

22.1 Modifications On a Non-Firm Basis: ............................................................89

22.2 Modification On a Firm Basis: ......................................................................90

23 SALE OR ASSIGNMENT OF TRANSMISSION SERVICE ..............................................91

23.1 Procedures for Assignment or Transfer of Service: ......................................91

23.2 Limitations on Assignment or Transfer of Service: ......................................92

23.3 Information on Assignment or Transfer of Service: .....................................93

24 METERING AND POWER FACTOR CORRECTION AT RECEIPT AND DELIVERY 

POINTS(S) .......................................................................................................................93

24.1 Transmission Customer Obligations: ............................................................93

24.2 Transmission Provider Access to Metering Data:.........................................94

24.3 Power Factor:.................................................................................................94

25 COMPENSATION FOR TRANSMISSION SERVICE ......................................................94

26 STRANDED COST RECOVERY .................................................................................94

27 COMPENSATION FOR NEW FACILITIES AND REDISPATCH COSTS ..........................95

III. NETWORK INTEGRATION TRANSMISSION SERVICE .............................95

28 NATURE OF NETWORK INTEGRATION TRANSMISSION SERVICE ............................96

28.1 Scope of Service:...........................................................................................96

28.2 Transmission Provider Responsibilities: .......................................................96

28.3 Network Integration Transmission Service:..................................................97

28.4 Secondary Service: ........................................................................................97

28.5 Real Power Losses:........................................................................................98

28.6 Restrictions on Use of Service: .....................................................................98

29 INITIATING SERVICE...............................................................................................99

29.1 Condition Precedent for Receiving Service: .................................................99

29.2 Application Procedures: ..............................................................................100

29.3 Technical Arrangements to be Completed Prior to Commencement of 

Service: ....................................................................................................................106
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 7 

29.4 Network Customer Facilities:......................................................................107

29.5 Filing of Service Agreement: ......................................................................107

30 NETWORK RESOURCES ........................................................................................108

30.1 Designation of Network Resources:............................................................108

30.2 Designation of New Network Resources: ...................................................108

30.3 Termination of Network Resources: ...........................................................109

30.4 Operation of Network Resources: ...............................................................111

30.5 Network Customer Redispatch Obligation:.................................................112

30.6 Transmission Arrangements for Network Resources Not Physically 

Interconnected With The Transmission Provider:...................................................112

30.7 Limitation on Designation of Network Resources:.....................................113

30.8 Use of Interface Capacity by the Network Customer: ................................113

30.9 Network Customer Owned Transmission Facilities:...................................113

31 DESIGNATION OF NETWORK LOAD ......................................................................114

31.1 Network Load:.............................................................................................114

31.2 New Network Loads Connected With the Transmission Provider: ............115

31.3 Network Load Not Physically Interconnected with the Transmission 

Provider: ..................................................................................................................115

31.4 New Interconnection Points: .......................................................................116

31.5 Changes in Service Requests:......................................................................116

31.6 Annual Load and Resource Information Updates: ......................................117

32 ADDITIONAL STUDY PROCEDURES FOR NETWORK INTEGRATION TRANSMISSION 

SERVICE REQUESTS......................................................................................................117

32.1 Notice of Need for System Impact Study:...................................................117

32.2 System Impact Study Agreement and Cost Reimbursement: .....................118

32.3 System Impact Study Procedures:...............................................................119

32.4 Facilities Study Procedures: ........................................................................121

32.5 Penalties for Failure to Meet Study Deadlines:...........................................123

33 LOAD SHEDDING AND CURTAILMENTS................................................................123

33.1 Procedures: ..................................................................................................123

33.2 Transmission Constraints: ...........................................................................123

33.3 Cost Responsibility for Relieving Transmission Constraints: ....................124

33.4 Curtailments of Scheduled Deliveries:........................................................125

33.5 Allocation of Curtailments: .........................................................................125

33.6 Load Shedding:............................................................................................125

33.7 System Reliability: ......................................................................................126

34 RATES AND CHARGES ..........................................................................................127

34.1 Monthly Demand Charge: ...........................................................................127
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 8 

34.2 Determination of Network Customer's Monthly Network Load:................127

34.3 Determination of Transmission Provider's Monthly Transmission System 

Load: .....................................................................................................................128

34.4 Redispatch Charge:......................................................................................128

34.5 Stranded Cost Recovery: .............................................................................128

35 OPERATING ARRANGEMENTS ..............................................................................129

35.1 Operation under The Network Operating Agreement:................................129

35.2 Network Operating Agreement: ..................................................................129

35.3 Network Operating Committee: ..................................................................130

SCHEDULE 1 ................................................................................................................132

SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE ....................................132

SCHEDULE 2 ................................................................................................................133

REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION SOURCES 

SERVICE ......................................................................................................................133

SCHEDULE 3 ................................................................................................................135

REGULATION AND FREQUENCY RESPONSE SERVICE...............................................135

SCHEDULE 4 ................................................................................................................136

ENERGY IMBALANCE SERVICE..................................................................................136

SCHEDULE 5 ................................................................................................................138

OPERATING RESERVE - SPINNING RESERVE SERVICE.............................................138

SCHEDULE 6 ................................................................................................................139

OPERATING RESERVE - SUPPLEMENTAL RESERVE SERVICE ..................................139

SCHEDULE 7 ................................................................................................................140

LONG-TERM FIRM AND SHORT-TERM FIRM POINT-TO-POINT TRANSMISSION 

SERVICE ......................................................................................................................140

SCHEDULE 8 ................................................................................................................142

NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE...........................................142

SCHEDULE 9 ................................................................................................................144

GENERATOR IMBALANCE SERVICE...........................................................................144

ATTACHMENT A ........................................................................................................147

FORM OF SERVICE AGREEMENT FOR FIRM POINT-TO-POINT TRANSMISSION 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 9 

SERVICE ......................................................................................................................147

ATTACHMENT A-1.....................................................................................................151

FORM OF SERVICE AGREEMENT FOR THE RESALE, REASSIGNMENT OR TRANSFER 

OF POINT-TO-POINT TRANSMISSION SERVICE........................................................151

ATTACHMENT B ........................................................................................................155

FORM OF SERVICE AGREEMENT FOR NON-FIRM POINT-TO-POINT TRANSMISSION 

SERVICE ......................................................................................................................155

ATTACHMENT C ........................................................................................................157

METHODOLOGY TO ASSESS AVAILABLE TRANSFER CAPABILITY..........................157

ATTACHMENT D ........................................................................................................159

METHODOLOGY FOR COMPLETING A SYSTEM IMPACT STUDY ..............................159

ATTACHMENT E ........................................................................................................160

INDEX OF POINT-TO-POINT TRANSMISSION SERVICE CUSTOMERS.......................160

ATTACHMENT F.........................................................................................................161

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION SERVICE...161

ATTACHMENT G........................................................................................................162

NETWORK OPERATING AGREEMENT........................................................................162

ATTACHMENT H........................................................................................................163

ANNUAL TRANSMISSION REVENUE REQUIREMENT FOR NETWORK INTEGRATION 

TRANSMISSION SERVICE ............................................................................................163

ATTACHMENT I..........................................................................................................164

INDEX OF NETWORK INTEGRATION TRANSMISSION SERVICE CUSTOMERS..........164

ATTACHMENT J .........................................................................................................165

PROCEDURES FOR ADDRESSING PARALLEL FLOWS ................................................165

ATTACHMENT K........................................................................................................166

TRANSMISSION PLANNING PROCESS.........................................................................166

ATTACHMENT L ........................................................................................................168

CREDITWORTHINESS PROCEDURES ..........................................................................168
(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. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 12 

1.8 Curtailment: 

A reduction in firm or non-firm transmission service in response to a transfer 

capability shortage as a result of system reliability conditions. 

1.9 Delivering Party: 

The entity supplying capacity and energy to be transmitted at Point(s) of 

Receipt. 

1.10 Designated Agent: 

Any entity that performs actions or functions on behalf of the Transmission 

Provider, an Eligible Customer, or the Transmission Customer required under 

the Tariff. 

1.11 Direct Assignment Facilities: 

Facilities or portions of facilities that are constructed by the Transmission 

Provider for the sole use/benefit of a particular Transmission Customer 

requesting service under the Tariff. Direct Assignment Facilities shall be 

specified in the Service Agreement that governs service to the Transmission 

Customer and shall be subject to Commission approval. 

1.12 Eligible Customer: 

i. Any electric utility (including the Transmission Provider and any 

power marketer), Federal power marketing agency, or any person 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 13 

generating electric energy for sale for resale is an Eligible Customer 

under the Tariff. Electric energy sold or produced by such entity may 

be electric energy produced in the United States, Canada or Mexico. 

However, with respect to transmission service that the Commission is 

prohibited from ordering by Section 212(h) of the Federal Power Act, 

such entity is eligible only if the service is provided pursuant to a state 

requirement that the Transmission Provider offer the unbundled 

transmission service, or pursuant to a voluntary offer of such service by 

the Transmission Provider. 

ii. Any retail customer taking unbundled transmission service pursuant to 

a state requirement that the Transmission Provider offer the 

transmission service, or pursuant to a voluntary offer of such service by 

the Transmission Provider, is an Eligible Customer under the Tariff. 

1.13 Facilities Study: 

An engineering study conducted by the Transmission Provider to determine 

the required modifications to the Transmission Provider's Transmission 

System, including the cost and scheduled completion date for such 

modifications, that will be required to provide the requested transmission 

service. 

1.14 Firm Point-To-Point Transmission Service: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 14 

Transmission Service under this Tariff that is reserved and/or scheduled 

between specified Points of Receipt and Delivery pursuant to Part II of this 

Tariff. 

1.15 Good Utility Practice: 

Any of the practices, methods and acts engaged in or approved by a significant 

portion of the electric utility industry during the relevant time period, or any of 

the practices, methods and acts which, in the exercise of reasonable judgment 

in light of the facts known at the time the decision was made, could have been 

expected to accomplish the desired result at a reasonable cost consistent with 

good business practices, reliability, safety and expedition. Good Utility 

Practice is not intended to be limited to the optimum practice, method, or act 

to the exclusion of all others, but rather to be acceptable practices, methods, or 

acts generally accepted in the region, including those practices required by 

Federal Power Act section 215(a)(4). 

1.16 Interruption: 

A reduction in non-firm transmission service due to economic reasons 

pursuant to Section 14.7. 

1.17 Load Ratio Share: 

Ratio of a Transmission Customer's Network Load to the Transmission 

Provider's total load computed in accordance with Sections 34.2 and 34.3 of 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 15 

the Network Integration Transmission Service under Part III of the Tariff and 

calculated on a rolling twelve month basis. 

1.18 Load Shedding: 

The systematic reduction of system demand by temporarily decreasing load in 

response to transmission system or area capacity shortages, system instability, 

or voltage control considerations under Part III of the Tariff. 

1.19 Long-Term Firm Point-To-Point Transmission Service: 

Firm Point-To-Point Transmission Service under Part II of the Tariff with a 

term of one year or more. 

1.20 Native Load Customers: 

The wholesale and retail power customers of the Transmission Provider on 

whose behalf the Transmission Provider, by statute, franchise, regulatory 

requirement, or contract, has undertaken an obligation to construct and operate 

the Transmission Provider's system to meet the reliable electric needs of such 

customers. 

1.21 Network Customer: 

An entity receiving transmission service pursuant to the terms of the 

Transmission Provider's Network Integration Transmission Service under Part 

III of the Tariff. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 16 

1.22 Network Integration Transmission Service: 

The transmission service provided under Part III of the Tariff. 

1.23 Network Load: 

The load that a Network Customer designates for Network Integration 

Transmission Service under Part III of the Tariff. The Network Customer's 

Network Load shall include all load served by the output of any Network 

Resources designated by the Network Customer. A Network Customer may 

elect to designate less than its total load as Network Load but may not 

designate only part of the load at a discrete Point of Delivery. Where a 

Eligible Customer has elected not to designate a particular load at discrete 

points of delivery as Network Load, the Eligible Customer is responsible for 

making separate arrangements under Part II of the Tariff for any Point-ToPoint Transmission Service that may be necessary for such non-designated 

load. 

1.24 Network Operating Agreement: 

An executed agreement that contains the terms and conditions under which the 

Network Customer shall operate its facilities and the technical and operational 

matters associated with the implementation of Network Integration 

Transmission Service under Part III of the Tariff. 

1.25 Network Operating Committee: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 17 

A group made up of representatives from the Network Customer(s) and the 

Transmission Provider established to coordinate operating criteria and other 

technical considerations required for implementation of Network Integration 

Transmission Service under Part III of this Tariff. 

1.26 Network Resource: 

Any designated generating resource owned, purchased or leased by a Network 

Customer under the Network Integration Transmission Service Tariff. 

Network Resources do not include any resource, or any portion thereof, that is 

committed for sale to third parties or otherwise cannot be called upon to meet 

the Network Customer's Network Load on a non-interruptible basis, except for 

purposes of fulfilling obligations under a Commission-approved reserve 

sharing program. 

1.27 Network Upgrades: 

Modifications or additions to transmission-related facilities that are integrated 

with and support the Transmission Provider's overall Transmission System for 

the general benefit of all users of such Transmission System. 

1.28 Non-Firm Point-To-Point Transmission Service: 

Point-To-Point Transmission Service under the Tariff that is reserved and 

scheduled on an as-available basis and is subject to Curtailment or 

Interruption as set forth in Section 14.7 under Part II of this Tariff. Non-Firm 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 18 

Point-To-Point Transmission Service is available on a stand-alone basis for 

periods ranging from one hour to one month. 

1.29 Non-Firm Sale: 

An energy sale for which receipt or delivery may be interrupted for any reason 

or no reason, without liability on the part of either the buyer or seller. 

1.30 Open Access Same-Time Information System (OASIS): 

The information system and standards of conduct contained in Part 37 of the 

Commission's regulations and all additional requirements implemented by 

subsequent Commission orders dealing with OASIS. 

1.31 Part I: 

Tariff Definitions and Common Service Provisions contained in Sections 2 

through 12. 

1.32 Part II: 

Tariff Sections 13 through 27 pertaining to Point-To-Point Transmission 

Service in conjunction with the applicable Common Service Provisions of Part 

I and appropriate Schedules and Attachments. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 19 

1.33 Part III: 

Tariff Sections 28 through 35 pertaining to Network Integration Transmission 

Service in conjunction with the applicable Common Service Provisions of Part 

I and appropriate Schedules and Attachments. 

1.34 Parties: 

The Transmission Provider and the Transmission Customer receiving service 

under the Tariff. 

1.35 Point(s) of Delivery: 

Point(s) on the Transmission Provider's Transmission System where capacity 

and energy transmitted by the Transmission Provider will be made available to 

the Receiving Party under Part II of the Tariff. The Point(s) of Delivery shall 

be specified in the Service Agreement for Long-Term Firm Point-To-Point 

Transmission Service. 

1.36 Point(s) of Receipt: 

Point(s) of interconnection on the Transmission Provider's Transmission 

System where capacity and energy will be made available to the Transmission 

Provider by the Delivering Party under Part II of the Tariff. The Point(s) of 

Receipt shall be specified in the Service Agreement for Long-Term Firm 

Point-To-Point Transmission Service. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 20 

1.37 Point-To-Point Transmission Service: 

The reservation and transmission of capacity and energy on either a firm or 

non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery under 

Part II of the Tariff. 

1.38 Power Purchaser: 

The entity that is purchasing the capacity and energy to be transmitted under 

the Tariff. 

1.39 Pre-Confirmed Application: 

An Application that commits the Eligible Customer to execute a Service 

Agreement upon receipt of notification that the Transmission Provider can 

provide the requested Transmission Service. 

1.40 Receiving Party: 

The entity receiving the capacity and energy transmitted by the Transmission 

Provider to Point(s) of Delivery. 

1.41 Regional Transmission Group (RTG): 

A voluntary organization of transmission owners, transmission users and other 

entities approved by the Commission to efficiently coordinate transmission 

planning (and expansion), operation and use on a regional (and interregional) 

basis. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 21 

1.42 Reserved Capacity: 

The maximum amount of capacity and energy that the Transmission Provider 

agrees to transmit for the Transmission Customer over the Transmission 

Provider's Transmission System between the Point(s) of Receipt and the 

Point(s) of Delivery under Part II of the Tariff. Reserved Capacity shall be 

expressed in terms of whole megawatts on a sixty (60) minute interval 

(commencing on the clock hour) basis. 

1.43 Service Agreement: 

The initial agreement and any amendments or supplements thereto entered 

into by the Transmission Customer and the Transmission Provider for service 

under the Tariff. 

1.44 Service Commencement Date: 

The date the Transmission Provider begins to provide service pursuant to the 

terms of an executed Service Agreement, or the date the Transmission 

Provider begins to provide service in accordance with Section 15.3 or Section 

29.1 under the Tariff. 

1.45 Short-Term Firm Point-To-Point Transmission Service: 

Firm Point-To-Point Transmission Service under Part II of the Tariff with a 

term of less than one year. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 22 

1.46 System Condition: 

A specified condition on the Transmission Provider’s system or on a 

neighboring system, such as a constrained transmission element or flowgate, 

that may trigger Curtailment of Long-Term Firm Point-to-Point Transmission 

Service using the curtailment priority pursuant to Section 13.6. Such 

conditions must be identified in the Transmission Customer’s Service 

Agreement. 

1.47 System Impact Study: 

An assessment by the Transmission Provider of (i) the adequacy of the 

Transmission System to accommodate a request for either Firm Point-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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 23 

the Commission, a proposed unexecuted Service Agreement to receive 

transmission service under Part II of the Tariff. This term is used in the Part I 

Common Service Provisions to include customers receiving transmission 

service under Part II and Part III of this Tariff. 

1.50 Transmission Provider: 

The public utility (or its Designated Agent) that owns, controls, or operates 

facilities used for the transmission of electric energy in interstate commerce 

and provides transmission service under the Tariff. 

1.51 Transmission Provider's Monthly Transmission System Peak: 

The maximum firm usage of the Transmission Provider's Transmission 

System in a calendar month. 

1.52 Transmission Service: 

Point-To-Point Transmission Service provided under Part II of the Tariff on a 

firm and non-firm basis. 

1.53 Transmission System: 

The facilities owned, controlled or operated by the Transmission Provider that 

are used to provide transmission service under Part II and Part III of the Tariff. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 24 

2 Initial Allocation and Renewal Procedures 

2.1 Initial Allocation of Available Transfer Capability: 

For purposes of determining whether existing capability on the Transmission 

Provider's Transmission System is adequate to accommodate a request for 

firm service under this Tariff, all Completed Applications for new firm 

transmission service received during the initial sixty (60) day period 

commencing with the effective date of the Tariff will be deemed to have been 

filed simultaneously. A lottery system conducted by an independent party 

shall be used to assign priorities for Completed Applications filed 

simultaneously. All Completed Applications for firm transmission service 

received after the initial sixty (60) day period shall be assigned a priority 

pursuant to Section 13.2. 

2.2 Reservation Priority For Existing Firm Service Customers: 

Existing firm service customers (wholesale requirements and 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 25 

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 longest competing request 

by any new Eligible Customer and to pay the current just and reasonable rate, 

as approved by the Commission, for such service; provided that, the firm 

service customer shall have a right of first refusal at the end of such service 

only if the new contract is for five years or more. The existing firm service 

customer must provide notice to the Transmission Provider whether it will 

exercise its right of first refusal no less than one year prior to the expiration 

date of its transmission service agreement. This transmission reservation 

priority for existing firm service customers is an ongoing right that may be 

exercised at the end of all firm contract terms of five years or longer. Service 

agreements subject to a right of first refusal entered into prior to [the date of 

the Transmission Provider’s filing adopting the reformed rollover language 

herein in compliance with Order No. 890] or associated with a transmission 

service request received prior to July 13, 2007, unless terminated, will become 

subject to the five year/one year requirement on the first rollover date after 

[the date of the Transmission Provider’s filing adopting the reformed rollover 

language herein in compliance with Order No. 890]; provided that, the oneyear notice requirement shall apply to such service agreements with five years 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 26 

or more left in their terms as of the [date of the Transmission Provider’s filing 

adopting the reformed rollover language herein in compliance with Order No. 

890]. 

3 Ancillary Services 

 Ancillary Services are needed with transmission service to maintain 

reliability within and among the Control Areas affected by the transmission 

service. The Transmission Provider is required to provide (or offer to arrange with 

the local Control Area operator as discussed below), and the Transmission 

Customer is required to purchase, the following Ancillary Services (i) Scheduling, 

System Control and Dispatch, and (ii) Reactive Supply and Voltage Control from 

Generation or Other Sources. 

 The Transmission Provider is required to offer to provide (or offer to 

arrange with the local Control Area operator as discussed below) the following 

Ancillary Services only to the Transmission Customer serving load within the 

Transmission Provider's Control Area (i) Regulation and Frequency Response, (ii) 

Energy Imbalance, (iii) Operating Reserve - Spinning, 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 selfsupply. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 27 

 The Transmission Provider is required to provide (or offer to arrange with 

the local Control Area Operator as discussed below), to the extent it is physically 

feasible to do so from its resources or from resources available to it, Generator 

Imbalance Service when Transmission Service is used to deliver energy from a 

generator located within its Control Area. The Transmission Customer using 

Transmission Service to deliver energy from a generator located within the 

Transmission Provider’s Control Area is required to acquire Generator Imbalance 

Service, whether from the Transmission Provider, from a third party, or by selfsupply. 

 The Transmission Customer may not decline the Transmission Provider's 

offer of Ancillary Services unless it demonstrates that it has acquired the Ancillary 

Services from another source. The Transmission Customer must list in its 

Application which Ancillary Services it will purchase from the Transmission 

Provider. A Transmission Customer that exceeds its firm reserved capacity at any 

Point of Receipt or Point of Delivery or an Eligible Customer that uses 

Transmission Service at a Point of Receipt or Point of Delivery that it has not 

reserved is required to pay for all of the Ancillary Services identified in this 

section that were provided by the Transmission Provider associated with the 

unreserved service. The Transmission Customer or Eligible Customer will pay for 

Ancillary Services based on the amount of transmission service it used but did not 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 28 

reserve. 

 If the Transmission Provider is a public utility providing transmission 

service but is not a Control Area operator, it may be unable to provide some or all 

of the Ancillary Services. In this case, the Transmission Provider can fulfill its 

obligation to provide Ancillary Services by acting as the Transmission Customer's 

agent to secure these Ancillary Services from the Control Area operator. The 

Transmission Customer may elect to (i) have the Transmission Provider act as its 

agent, (ii) secure the Ancillary Services directly from the Control Area operator, or 

(iii) secure the Ancillary Services (discussed in Schedules 3, 4, 5, 6 and 9) from a 

third party or by self-supply when technically feasible. 

 The Transmission Provider shall specify the rate treatment and all related 

terms and conditions in the event of an unauthorized use of Ancillary Services by 

the Transmission Customer. 

 The specific Ancillary Services, prices and/or compensation methods are 

described on the Schedules that are attached to and made a part of the Tariff. 

Three principal requirements apply to discounts for Ancillary Services provided 

by the Transmission Provider in conjunction with its provision of transmission 

service as follows: (1) any offer of a discount made by the Transmission Provider 

must be announced to all Eligible Customers solely by posting on the OASIS, (2) 

any customer-initiated requests for discounts (including requests for use by one's 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 29 

wholesale merchant or an Affiliate's use) must occur solely by posting on the 

OASIS, and (3) once a discount is negotiated, details must be immediately posted 

on the OASIS. A discount agreed upon for an Ancillary Service must be offered 

for the same period to all Eligible Customers on the Transmission Provider's 

system. Sections 3.1 through 3.7 below list the seven Ancillary Services. 

3.1 Scheduling, System Control and Dispatch Service: 

The rates and/or methodology are described in Schedule 1. 

3.2 Reactive Supply and Voltage Control from Generation or Other 

Sources Service: 

The rates and/or methodology are described in Schedule 2. 

3.3 Regulation and Frequency Response Service: 

Where applicable the rates and/or methodology are described in Schedule 3. 

3.4 Energy Imbalance Service: 

Where applicable the rates and/or methodology are described in Schedule 4. 

3.5 Operating Reserve - Spinning Reserve Service: 

Where applicable the rates and/or methodology are described in Schedule 5. 

3.6 Operating Reserve - Supplemental Reserve Service: 

Where applicable the rates and/or methodology are described in Schedule 6. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 30 

3.7 Generator Imbalance Service: 

Where applicable the rates and/or methodology are described in Schedule 9. 

4 Open Access Same-Time Information System (OASIS) 

 Terms and conditions regarding Open Access Same-Time Information 

System and standards of conduct are set forth in 18 CFR § 37 of the Commission's 

regulations (Open Access Same-Time Information System and Standards of 

Conduct for Public Utilities) and 18 C.F.R. § 38 of the Commission’s regulations 

(Business Practice Standards and Communication Protocols for Public Utilities). 

In the event available transfer capability as posted on the OASIS is insufficient to 

accommodate a request for firm transmission service, additional studies may be 

required as provided by this Tariff pursuant to Sections 19 and 32. 

 The Transmission Provider shall post on OASIS and its public website an 

electronic link to all rules, standards and practices that (i) relate to the terms and 

conditions of transmission service, (ii) are not subject to a North American Energy 

Standards Board (NAESB) copyright restriction, and (iii) are not otherwise 

included in this Tariff. The Transmission Provider shall post on OASIS and on its 

public website an electronic link to the NAESB website where any rules, standards 

and practices that are protected by copyright may be obtained. The Transmission 

Provider shall also post on OASIS and its public website an electronic link to a 

statement of the process by which the Transmission Provider shall add, delete or 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 31 

otherwise modify the rules, standards and practices that are not included in this 

tariff. Such process shall set forth the means by which the Transmission Provider 

shall provide reasonable advance notice to Transmission Customers and Eligible 

Customers of any such additions, deletions or modifications, the associated 

effective date, and any additional implementation procedures that the 

Transmission Provider deems appropriate. 

5 Local Furnishing Bonds 

5.1 Transmission Providers That Own Facilities Financed by Local 

Furnishing Bonds: 

This provision is applicable only to Transmission Providers that have financed 

facilities for the local furnishing of electric energy with tax-exempt bonds, as 

described in Section 142(f) of the Internal Revenue Code ("local furnishing 

bonds"). Notwithstanding any other provision of this Tariff, the Transmission 

Provider shall not be required to provide transmission service to any Eligible 

Customer pursuant to this Tariff if the provision of such transmission service 

would jeopardize the tax-exempt status of any local furnishing bond(s) used to 

finance the Transmission Provider's facilities that would be used in providing 

such transmission service. 

5.2 Alternative Procedures for Requesting Transmission Service: 

(i) If the Transmission Provider determines that the provision of 

transmission service requested by an Eligible Customer would 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 32 

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 

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. 
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6 Reciprocity 

 A Transmission Customer receiving transmission service under this Tariff 

agrees to provide comparable transmission service that it is capable of providing to 

the Transmission Provider on similar terms and conditions over facilities used for 

the transmission of electric energy owned, controlled or operated by the 

Transmission Customer and over facilities used for the transmission of electric 

energy owned, controlled or operated by the Transmission Customer's corporate 

Affiliates. A Transmission Customer that is a member of, or takes transmission 

service from, a power pool, Regional Transmission Group, Regional Transmission 

Organization (RTO), Independent System Operator (ISO) or other transmission 

organization approved by the Commission for the operation of transmission 

facilities also agrees to provide comparable transmission service to the 

transmission-owning members of such power pool and Regional Transmission 

Group, RTO, ISO or other transmission organization on similar terms and 

conditions over facilities used for the transmission of electric energy owned, 

controlled or operated by the Transmission Customer and over facilities used for 

the transmission of electric energy owned, controlled or operated by the 

Transmission Customer's corporate Affiliates. 

 This reciprocity requirement applies not only to the Transmission Customer 

that obtains transmission service under the Tariff, but also to all parties to a 
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Original Sheet No. 34 

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. 
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7.2 Interest on Unpaid Balances: 

Interest on any unpaid amounts (including amounts placed in escrow) shall be 

calculated in accordance with the methodology specified for interest on 

refunds in the Commission's regulations at 18 C.F.R.  35.19a(a)(2)(iii). 

Interest on delinquent amounts shall be calculated from the due date of the bill 

to the date of payment. When payments are made by mail, bills shall be 

considered as having been paid on the date of receipt by the Transmission 

Provider. 

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 
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Original Sheet No. 36 

the Service Agreement as long as the Transmission Customer (i) continues to 

make all payments not in dispute, and (ii) pays into an independent escrow 

account the portion of the invoice in dispute, pending resolution of such 

dispute. If the Transmission Customer fails to meet these two requirements 

for continuation of service, then the Transmission Provider may provide 

notice to the Transmission Customer of its intention to suspend service in 

sixty (60) days, in accordance with Commission policy. 

8 Accounting for the Transmission Provider's Use of the Tariff 

 The Transmission Provider shall record the following amounts, as outlined 

below. 

8.1 Transmission Revenues: 

Include in a separate operating revenue account or subaccount the revenues it 

receives from Transmission Service when making Third-Party Sales under 

Part II of the Tariff. 

8.2 Study Costs and Revenues: 

Include in a separate transmission operating expense account or subaccount, 

costs properly chargeable to expense that are incurred to perform any System 

Impact Studies or Facilities Studies which the Transmission Provider conducts 

to determine if it must construct new transmission facilities or upgrades 

necessary for its own uses, including making Third-Party Sales under the 
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Original Sheet No. 37 

Tariff; and include in a separate operating revenue account or subaccount the 

revenues received for System Impact Studies or Facilities Studies performed 

when such amounts are separately stated and identified in the Transmission 

Customer's billing under the Tariff. 

9 Regulatory Filings 

 Nothing contained in the Tariff or any Service Agreement shall be 

construed as affecting in any way the right of the Transmission Provider to 

unilaterally make application to the Commission for a change in rates, terms and 

conditions, charges, classification of service, Service Agreement, rule or 

regulation under Section 205 of the Federal Power Act and pursuant to the 

Commission's rules 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 
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Original Sheet No. 38 

authorities, or any other cause beyond a Party’s control. A Force Majeure 

event does not include an act of negligence or intentional wrongdoing. 

Neither the Transmission Provider nor the Transmission Customer will be 

considered in default as to any obligation under this Tariff if prevented from 

fulfilling the obligation due to an event of Force Majeure. However, a Party 

whose performance under this Tariff is hindered by an event of Force Majeure 

shall make all reasonable efforts to perform its obligations under this Tariff. 

10.2 Indemnification: 

The Transmission Customer shall at all times indemnify, defend, and save the 

Transmission Provider harmless from, any and all damages, losses, claims, 

including claims and actions relating to injury to or death of any person or 

damage to property, demands, suits, recoveries, costs and expenses, court 

costs, attorney fees, and all other obligations by or to third parties, arising out 

of or resulting from the Transmission Provider’s performance of its 

obligations under this Tariff on behalf of the Transmission Customer, except 

in cases of negligence or intentional wrongdoing by the Transmission 

Provider. 
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11 Creditworthiness 

 The Transmission Provider will specify its Creditworthiness procedures in 

Attachment L. 

12 Dispute Resolution Procedures 

12.1 Internal Dispute Resolution Procedures: 

Any dispute between a Transmission Customer and the Transmission Provider 

involving transmission service under the Tariff (excluding applications for 

rate changes or other changes to the Tariff, or to any Service Agreement 

entered into under the Tariff, which shall be presented directly to the 

Commission for resolution) shall be referred to a designated senior 

representative of the Transmission Provider and a senior representative of the 

Transmission Customer for resolution on an informal basis as promptly as 

practicable. In the event the designated representatives are unable to resolve 

the dispute within thirty (30) days [or such other period as the Parties may 

agree upon] by mutual agreement, such dispute may be submitted to 

arbitration and resolved in accordance with the arbitration procedures set forth 

below. 

12.2 External Arbitration Procedures: 

Any arbitration initiated under the Tariff shall be conducted before a single 

neutral arbitrator appointed by the Parties. If the Parties fail to agree upon a 

single arbitrator within ten (10) days of the referral of the dispute to 
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arbitration, each Party shall choose one arbitrator who shall sit on a threemember arbitration panel. The two arbitrators so chosen shall within twenty 

(20) days select a third arbitrator to chair the arbitration panel. In either case, 

the arbitrators shall be knowledgeable in electric utility matters, including 

electric transmission and bulk power issues, and shall not have any current or 

past substantial business or financial relationships with any party to the 

arbitration (except prior arbitration). The arbitrator(s) shall provide each of 

the Parties an opportunity to be heard and, except as otherwise provided 

herein, shall generally conduct the arbitration in accordance with the 

Commercial Arbitration Rules of the American Arbitration Association and 

any applicable Commission regulations or Regional Transmission Group 

rules. 

12.3 Arbitration Decisions: 

Unless otherwise agreed, the arbitrator(s) shall render a decision within ninety 

(90) days of appointment and shall notify the Parties in writing of such 

decision and the reasons therefor. The arbitrator(s) shall be authorized only to 

interpret and apply the provisions of the Tariff and any Service Agreement 

entered into under the Tariff and shall have no power to modify or change any 

of the above in any manner. The decision of the arbitrator(s) shall be final and 

binding upon the Parties, and judgment on the award may be entered in any 
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court having jurisdiction. The decision of the arbitrator(s) may be appealed 

solely on the grounds that the conduct of the arbitrator(s), or the decision 

itself, violated the standards set forth in the Federal Arbitration Act and/or the 

Administrative Dispute Resolution Act. The final decision of the arbitrator 

must also be filed with the Commission if it affects jurisdictional rates, terms 

and conditions of service or facilities. 

12.4 Costs: 

Each Party shall be responsible for its own costs incurred during the 

arbitration process and for the following costs, if applicable: 

1. the cost of the arbitrator chosen by the Party to sit on the three member 

panel and one half of the cost of the third arbitrator chosen; or 

2. one half the cost of the single arbitrator jointly chosen by the Parties. 

12.5 Rights Under The Federal Power Act: 

Nothing in this section shall restrict the rights of any party to file a Complaint 

with the Commission under relevant provisions of the Federal Power Act. 

II. POINT-TO-POINT TRANSMISSION SERVICE 

Preamble 

 The Transmission Provider will provide Firm and Non-Firm Point-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 
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designated Point(s) of Receipt and the transfer of such capacity and energy to designated 

Point(s) of Delivery. 

13 Nature of Firm Point-To-Point Transmission Service 

13.1 Term: 

The minimum term of Firm Point-To-Point Transmission Service shall be one 

day and the maximum term shall be specified in the Service Agreement. 

13.2 Reservation Priority: 

(i) Long-Term Firm Point-To-Point Transmission Service shall be 

available on a first-come, first-served basis, i.e., in the 

chronological sequence in which each Transmission Customer has 

requested service. 

(ii) Reservations for Short-Term Firm Point-To-Point Transmission 

Service will be conditional based upon the length of the requested 

transaction or reservation. However, Pre-Confirmed Applications 

for Short-Term Point-to-Point Transmission Service will receive 

priority over earlier-submitted requests that are not PreConfirmed and that have equal or shorter duration. Among 

requests or reservations with the same duration and, as relevant, 

pre-confirmation status (pre-confirmed, confirmed, or not 

confirmed), priority will be given to an Eligible Customer’s 
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request or reservation that offers the highest price, followed by 

the date and time of the request or reservation. 

(iii) If the Transmission System becomes oversubscribed, requests for 

service may preempt competing reservations up to the following 

conditional reservation deadlines: one day before the 

commencement of daily service, one week before the 

commencement of weekly service, and one month before the 

commencement of monthly service. Before the conditional 

reservation deadline, if available transfer capability is insufficient 

to satisfy all requests and reservations, an Eligible Customer with 

a reservation for shorter term service or equal duration service 

and lower price has the right of first refusal to match any longer 

term request or equal duration service with a higher price before 

losing its reservation priority. A longer term competing request 

for Short-Term Firm Point-To-Point Transmission Service will be 

granted if the Eligible Customer with the right of first refusal does 

not agree to match the competing request within 24 hours (or 

earlier if necessary to comply with the scheduling deadlines 

provided in section 13.8) from being notified by the Transmission 

Provider of a longer-term competing request for Short-Term Firm 
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Point-To-Point Transmission Service. When a longer duration 

request preempts multiple shorter duration reservations, the 

shorter duration reservations shall have simultaneous 

opportunities to exercise the right of first refusal. Duration, price 

and time of response will be used to determine the order by which 

the multiple shorter duration reservations will be able to exercise 

the right of first refusal. After the conditional reservation 

deadline, service will commence pursuant to the terms of Part II 

of the Tariff. 

(iv) Firm Point-To-Point Transmission Service will always have a 

reservation priority over Non-Firm Point-To-Point Transmission 

Service under the Tariff. All Long-Term Firm Point-To-Point 

Transmission Service will have equal reservation priority with 

Native Load Customers and Network Customers. Reservation 

priorities for existing firm service customers are provided in 

Section 2.2. 

13.3 Use of Firm Transmission Service by the Transmission Provider: 

The Transmission Provider will be subject to the rates, terms and conditions of 

Part II of the Tariff when making Third-Party Sales under (i) agreements 

executed on or after [insert date sixty (60) days after publication in Federal 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 45 

Register] or (ii) agreements executed prior to the aforementioned date that the 

Commission requires to be unbundled, by the date specified by the 

Commission. The Transmission Provider will maintain separate accounting, 

pursuant to Section 8, for any use of the Point-To-Point Transmission Service 

to make Third-Party Sales. 

13.4 Service Agreements: 

The Transmission Provider shall offer a standard form Firm Point-To-Point 

Transmission Service Agreement (Attachment A) to an Eligible Customer 

when it submits a Completed Application for Long-Term Firm Point-To-Point 

Transmission Service. The Transmission Provider shall offer a standard form 

Firm Point-To-Point Transmission Service Agreement (Attachment A) to an 

Eligible Customer when it first submits a Completed Application for 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. An Eligible Customer that uses Transmission 

Service at a Point of Receipt or Point of Delivery that it has not reserved and 

that has not executed a Service Agreement will be deemed, for purposes of 

assessing any appropriate charges and penalties, to have executed the 

appropriate Service Agreement. The Service Agreement shall, when 
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applicable, specify any conditional curtailment options selected by the 

Transmission Customer. Where the Service Agreement contains conditional 

curtailment options and is subject to a biennial reassessment as described in 

Section 15.4, the Transmission Provider shall provide the Transmission 

Customer notice of any changes to the curtailment conditions no less than 90 

days prior to the date for imposition of new curtailment conditions. 

Concurrent with such notice, the Transmission Provider shall provide the 

Transmission Customer with the reassessment study and a narrative 

description of the study, including the reasons for changes to the number of 

hours per year or System Conditions under which conditional curtailment may 

occur. 

13.5 Transmission Customer Obligations for Facility Additions or 

Redispatch Costs: 

In cases where the Transmission Provider determines that the Transmission 

System is not capable of providing Firm Point-To-Point Transmission Service 

without (1) degrading or impairing the reliability of service to Native Load 

Customers, Network Customers and other Transmission Customers taking 

Firm Point-To-Point Transmission Service, or (2) interfering with the 

Transmission Provider's ability to meet prior firm contractual commitments to 

others, the Transmission Provider will be obligated to expand or upgrade its 
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Transmission System pursuant to the terms of Section 15.4. The Transmission 

Customer must agree to compensate the Transmission Provider for any 

necessary transmission facility additions pursuant to the terms of Section 27. 

To the extent the Transmission Provider can relieve any system constraint by 

redispatching the Transmission Provider's resources, it shall do so, provided 

that the Eligible Customer agrees to compensate the Transmission Provider 

pursuant to the terms of Section 27 and agrees to either (i) compensate the 

Transmission Provider for any necessary transmission facility additions or (ii) 

accept the service subject to a biennial reassessment by the Transmission 

Provider of redispatch requirements as described in Section 15.4. Any 

redispatch, Network Upgrade or Direct Assignment Facilities costs to be 

charged to the Transmission Customer on an incremental basis under the 

Tariff will be specified in the Service Agreement prior to initiating service. 

13.6 Curtailment of Firm Transmission Service: 

In the event that a Curtailment on the Transmission Provider's Transmission 

System, or a portion thereof, is required to maintain reliable operation of such 

system and the system directly and indirectly interconnected with 

Transmission Provider’s Transmission System, Curtailments will be made on 

a non-discriminatory basis to the transaction(s) that effectively relieve the 

constraint. Transmission Provider may elect to implement such Curtailments 
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pursuant to the Transmission Loading Relief procedures specified in 

Attachment J. If multiple transactions require Curtailment, to the extent 

practicable and consistent with Good Utility Practice, the Transmission 

Provider will curtail service to Network Customers and Transmission 

Customers taking Firm Point-To-Point Transmission Service on a basis 

comparable to the curtailment of service to the Transmission Provider's Native 

Load Customers. All Curtailments will be made on a non-discriminatory 

basis, however, Non-Firm Point-To-Point Transmission Service shall be 

subordinate to Firm Transmission Service. Long-Term Firm Point-to-Point 

Service subject to conditions described in Section 15.4 shall be curtailed with 

secondary service in cases where the conditions apply, but otherwise will be 

curtailed on a pro rata basis with other Firm Transmission Service. When the 

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 
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Transmission Provider will notify all affected Transmission Customers in a 

timely manner of any scheduled Curtailments. 

13.7 Classification of Firm Transmission Service: 

(a) The Transmission Customer taking Firm Point-To-Point 

Transmission Service may (1) change its Receipt and Delivery 

Points to obtain service on a non-firm basis consistent with the 

terms of Section 22.1 or (2) request a modification of the Points 

of Receipt or Delivery on a firm basis pursuant to the terms of 

Section 22.2. 

(b) The Transmission Customer may purchase transmission service to 

make sales of capacity and energy from multiple generating units 

that are on the Transmission Provider's Transmission System. For 

such a purchase of transmission service, the resources will be 

designated as multiple Points of Receipt, unless the multiple 

generating units are at the same generating plant in which case the 

units would be treated as a single Point of Receipt. 

(c) The Transmission Provider shall provide firm deliveries of 

capacity and energy from the Point(s) of Receipt to the Point(s) of 

Delivery. Each Point of Receipt at which firm transmission 

capacity is reserved by the Transmission Customer shall be set 
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forth in the Firm Point-To-Point Service Agreement for LongTerm Firm Transmission Service along with a corresponding 

capacity reservation associated with each Point of Receipt. Points 

of Receipt and corresponding capacity reservations shall be as 

mutually agreed upon by the Parties for Short-Term Firm 

Transmission. Each Point of Delivery at which firm transfer 

capability is reserved by the Transmission Customer shall be set 

forth in the Firm Point-To-Point Service Agreement for LongTerm Firm Transmission Service along with a corresponding 

capacity reservation associated with each Point of Delivery. 

Points of Delivery and corresponding capacity reservations shall 

be as mutually agreed upon by the Parties for Short-Term Firm 

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 
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Original Sheet No. 51 

Transmission Provider shall specify the rate treatment and all 

related terms and conditions applicable in the event that a 

Transmission Customer (including Third-Party Sales by the 

Transmission Provider) exceeds its firm reserved capacity at any 

Point of Receipt or Point of Delivery or uses Transmission 

Service at a Point of Receipt or Point of Delivery that it has not 

reserved. 

13.8 Scheduling of Firm Point-To-Point Transmission Service: 

Schedules for the Transmission Customer's Firm Point-To-Point Transmission 

Service must be submitted to the Transmission Provider no later than 10:00 

a.m. [or a reasonable time that is generally accepted in the region and is 

consistently adhered to by the Transmission Provider] of the day prior to 

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 
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Original Sheet No. 52 

of receipt into units of 1,000 kW per hour for scheduling and billing purposes. 

Scheduling changes will be permitted up to twenty (20) minutes [or a 

reasonable time that is generally accepted in the region and is consistently 

adhered to by the Transmission Provider] before the start of the next clock 

hour provided that the Delivering Party and Receiving Party also agree to the 

schedule modification. The Transmission Provider will furnish to the 

Delivering Party's system operator, hour-to-hour schedules equal to those 

furnished by the Receiving Party (unless reduced for losses) and shall deliver 

the capacity and energy provided by such schedules. Should the Transmission 

Customer, Delivering Party or Receiving Party revise or terminate any 

schedule, such party shall immediately notify the Transmission Provider, and 

the Transmission Provider shall have the right to adjust accordingly the 

schedule for capacity and energy to be received and to be delivered. 

14 Nature of Non-Firm Point-To-Point Transmission Service 

14.1 Term: 

Non-Firm Point-To-Point Transmission Service will be available for periods 

ranging from one (1) hour to one (1) month. However, a Purchaser of 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) 
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so that the total time period for which the reservation applies is greater than 

one month, subject to the requirements of Section 18.3. 

14.2 Reservation Priority: 

Non-Firm Point-To-Point Transmission Service shall be available from 

transfer capability in excess of that needed for reliable service to Native Load 

Customers, Network Customers and other Transmission Customers taking 

Long-Term and Short-Term Firm Point-To-Point Transmission Service. A 

higher priority will be assigned first to requests or reservations with a longer 

duration of service and second to Pre-Confirmed Applications. In the event 

the Transmission System is constrained, competing requests of the same PreConfirmation status and equal duration will be prioritized based on the highest 

price offered by the Eligible Customer for the Transmission Service. Eligible 

Customers that have already reserved shorter term service have the right of 

first refusal to match any longer term request 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 
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Point-To-Point Transmission Service other than hourly transactions after 

notification by the Transmission Provider. Transmission service for Network 

Customers from resources other than designated Network Resources will have 

a higher priority than any Non-Firm Point-To-Point Transmission Service. 

Non-Firm Point-To-Point Transmission Service over secondary Point(s) of 

Receipt and Point(s) of Delivery will have the lowest reservation priority 

under the Tariff. 

14.3 Use of Non-Firm Point-To-Point Transmission Service by the 

Transmission Provider: 

The Transmission Provider will be subject to the rates, terms and conditions of 

Part II of the Tariff when making Third-Party Sales under (i) agreements 

executed on or after [insert date sixty (60) days after publication in Federal 

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 
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Original Sheet No. 55 

Customer when it first submits a Completed Application for Non-Firm PointTo-Point Transmission Service pursuant to the Tariff. Executed Service 

Agreements that contain the information required under the Tariff shall be 

filed with the Commission in compliance with applicable Commission 

regulations. 

14.5 Classification of Non-Firm Point-To-Point Transmission Service: 

Non-Firm Point-To-Point Transmission Service shall be offered under terms 

and conditions contained in Part II of the Tariff. The Transmission Provider 

undertakes no obligation under the Tariff to plan its Transmission System in 

order to have sufficient capacity for Non-Firm Point-To-Point Transmission 

Service. Parties requesting Non-Firm Point-To-Point Transmission Service 

for the transmission of firm power do so with the full realization that such 

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, 
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Original Sheet No. 56 

weekly or monthly basis, but not to exceed one month's reservation for any 

one Application, under Schedule 8. 

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service: 

Schedules for Non-Firm Point-To-Point Transmission Service must be 

submitted to the Transmission Provider no later than 2:00 p.m. [or a 

reasonable time that is generally accepted in the region and is consistently 

adhered to by the Transmission Provider] of the day prior to commencement 

of such service. Schedules submitted after 2:00 p.m. will be accommodated, if 

practicable. Hour-to-hour schedules of energy that is to be delivered must be 

stated in increments of 1,000 kW per hour [or a reasonable increment that is 

generally accepted in the region and is consistently adhered to by the 

Transmission Provider]. Transmission Customers within the Transmission 

Provider's service area with multiple requests for Transmission Service at a 

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 
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Original Sheet No. 57 

Delivering Party's system operator, hour-to-hour schedules equal to those 

furnished by the Receiving Party (unless reduced for losses) and shall deliver 

the capacity and energy provided by such schedules. Should the Transmission 

Customer, Delivering Party or Receiving Party revise or terminate any 

schedule, such party shall immediately notify the Transmission Provider, and 

the Transmission Provider shall have the right to adjust accordingly the 

schedule for capacity and energy to be received and to be delivered. 

14.7 Curtailment or Interruption of Service: 

The Transmission Provider reserves the right to Curtail, in whole or in part, 

Non-Firm Point-To-Point Transmission Service provided under the Tariff for 

reliability reasons when an emergency or other unforeseen condition threatens 

to impair or degrade the reliability of its Transmission System or the systems 

directly and indirectly interconnected with Transmission Provider’s 

Transmission System. Transmission Provider may elect to implement such 

Curtailments pursuant to the Transmission Loading Relief procedures 

specified in Attachment J. The Transmission Provider reserves the right to 

Interrupt, in whole or in part, 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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 58 

Point-To-Point Transmission Service of equal duration with a higher price, (4) 

transmission service for Network Customers from non-designated resources, 

or (5) transmission service for Firm Point-to-Point Transmission Service 

during conditional curtailment periods as described in Section 15.4. The 

Transmission Provider also will discontinue or reduce service to the 

Transmission Customer to the extent that deliveries for transmission are 

discontinued or reduced at the Point(s) of Receipt. Where required, 

Curtailments or Interruptions will be made on a non-discriminatory basis to 

the transaction(s) that effectively relieve the constraint, however, Non-Firm 

Point-To-Point Transmission Service shall be subordinate to Firm 

Transmission Service. If multiple transactions require Curtailment or 

Interruption, to the extent practicable and consistent with Good Utility 

Practice, Curtailments or Interruptions will be made to transactions of the 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 59 

Delivery will have a lower priority than any Non-Firm Point-To-Point 

Transmission Service under the Tariff. The Transmission Provider will 

provide advance notice of Curtailment or Interruption where such notice can 

be provided consistent with Good Utility Practice. 

15 Service Availability 

15.1 General Conditions: 

The Transmission Provider will provide Firm and Non-Firm Point-To-Point 

Transmission Service over, on or across its Transmission System to any 

Transmission Customer that has met the requirements of Section 16. 

15.2 Determination of Available Transfer Capability: 

A description of the Transmission Provider's specific methodology for 

assessing available transfer capability posted on the Transmission Provider's 

OASIS (Section 4) is contained in Attachment C of the Tariff. In the event 

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 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 60 

after the date the Transmission Customer provides written notification 

directing the Transmission Provider to file, an unexecuted Point-To-Point 

Service Agreement containing terms and conditions deemed appropriate by 

the Transmission Provider for such requested Transmission Service. The 

Transmission Provider shall commence providing Transmission Service 

subject to the Transmission Customer agreeing to (i) compensate the 

Transmission Provider at whatever rate the Commission ultimately determines 

to be just and reasonable, and (ii) comply with the terms and conditions of the 

Tariff including posting appropriate security deposits in accordance with the 

terms of Section 17.3. 

15.4 Obligation to Provide Transmission Service that Requires 

Expansion or Modification of the Transmission System, Redispatch 

or Conditional Curtailment: 

(a) If the Transmission Provider determines that it cannot 

accommodate a Completed Application for Firm Point-To-Point 

Transmission Service because of insufficient capability on its 

Transmission System, the Transmission Provider will use due 

diligence to expand or modify its Transmission System to provide 

the requested Firm Transmission Service, consistent with its 

planning obligations in Attachment K, provided the Transmission 

Customer agrees to compensate the Transmission Provider for 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 61 

such costs pursuant to the terms of Section 27. The Transmission 

Provider will conform to Good Utility Practice and its planning 

obligations in Attachment K, in determining the need for new 

facilities and in the design and construction of such facilities. The 

obligation applies only to those facilities that the Transmission 

Provider has the right to expand or modify. 

(b) If the Transmission Provider determines that it cannot 

accommodate a Completed Application for Long-Term Firm 

Point-To-Point Transmission Service because of insufficient 

capability on its Transmission System, the Transmission Provider 

will use due diligence to provide redispatch from its own 

resources until (i) Network Upgrades are completed for the 

Transmission Customer, (ii) the Transmission Provider 

determines through a biennial reassessment that it can no longer 

reliably provide the redispatch, or (iii) the Transmission Customer 

terminates the service because of redispatch changes resulting 

from the reassessment. A Transmission Provider shall not 

unreasonably deny self-provided redispatch or redispatch 

arranged by the Transmission Customer from a third party 

resource. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 62 

(c) If the Transmission Provider determines that it cannot 

accommodate a Completed Application for Long-Term Firm 

Point-To-Point Transmission Service because of insufficient 

capability on its Transmission System, the Transmission Provider 

will offer the Firm Transmission Service with the condition that 

the Transmission Provider may curtail the service prior to the 

curtailment of other Firm Transmission Service for a specified 

number of hours per year or during System Condition(s). If the 

Transmission Customer accepts the service, the Transmission 

Provider will use due diligence to provide the service until (i) 

Network Upgrades are completed for the Transmission Customer, 

(ii) the Transmission Provider determines through a biennial 

reassessment that it can no longer reliably provide such service, or 

(iii) the Transmission Customer terminates the service because 

the reassessment increased the number of hours per year of 

conditional curtailment or changed the System Conditions. 

15.5 Deferral of Service: 

The Transmission Provider may defer providing service until it completes 

construction of new transmission facilities or upgrades needed to provide Firm 

Point-To-Point Transmission Service whenever the Transmission Provider 
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Original Sheet No. 63 

determines that providing the requested service would, without such new 

facilities or upgrades, impair or degrade reliability to any existing firm 

services. 

15.6 Other Transmission Service Schedules: 

Eligible Customers receiving transmission service under other agreements on 

file with the Commission may continue to receive transmission service under 

those agreements until such time as those agreements may be modified by the 

Commission. 

15.7 Real Power Losses: 

Real Power Losses are associated with all transmission service. The 

Transmission Provider is not obligated to provide Real Power Losses. The 

Transmission Customer is responsible for replacing losses associated with all 

transmission service as calculated by the Transmission Provider. The 

applicable Real Power Loss factors are as follows: [To be completed by the 

Transmission Provider]. 

16 Transmission Customer Responsibilities 

16.1 Conditions Required of Transmission Customers: 

Point-To-Point Transmission Service shall be provided by the Transmission 

Provider only if the following conditions are satisfied by the Transmission 

Customer: 
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Original Sheet No. 64 

(a) The Transmission Customer has pending a Completed 

Application for service; 

(b) The Transmission Customer meets the creditworthiness criteria 

set forth in Section 11; 

(c) The Transmission Customer will have arrangements in place for 

any other transmission service necessary to effect the delivery 

from the generating source to the Transmission Provider prior to 

the time service under Part II of the Tariff commences; 

(d) The Transmission Customer agrees to pay for any facilities 

constructed and chargeable to such Transmission Customer under 

Part II of the Tariff, whether or not the Transmission Customer 

takes service for the full term of its reservation; 

(e) The Transmission Customer provides the information required by 

the Transmission Provider’s planning process established in 

Attachment K; and 

(f) The Transmission Customer has executed a Point-To-Point 

Service Agreement or has agreed to receive service pursuant to 

Section 15.3. 

16.2 Transmission Customer Responsibility for Third-Party 

Arrangements: 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 65 

Any scheduling arrangements that may be required by other electric systems 

shall be the responsibility of the Transmission Customer requesting service. 

The Transmission Customer shall provide, unless waived by the Transmission 

Provider, notification to the Transmission Provider identifying such systems 

and authorizing them to schedule the capacity and energy to be transmitted by 

the Transmission Provider pursuant to Part II of the Tariff on behalf of the 

Receiving Party at the Point of Delivery or the Delivering Party at the Point of 

Receipt. However, the Transmission Provider will undertake reasonable 

efforts to assist the Transmission Customer in making such arrangements, 

including without limitation, providing any information or data required by 

such other electric system pursuant to Good Utility Practice. 

17 Procedures for Arranging Firm Point-To-Point Transmission Service 

17.1 Application: 

A request for Firm Point-To-Point Transmission Service for periods of one 

year or longer must contain a written Application to: [Transmission Provider 

Name and Address], at least sixty (60) days in advance of the calendar month 

in which service is to commence. The Transmission Provider will consider 

requests for such firm service on shorter notice when feasible. Requests for 

firm service for periods of less than one year shall be subject to expedited 

procedures that shall be negotiated between the Parties within the time 
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Original Sheet No. 66 

constraints provided in Section 17.5. All Firm Point-To-Point Transmission 

Service requests should be submitted by entering the information listed below 

on the Transmission Provider's OASIS. Prior to implementation of the 

Transmission Provider's OASIS, a Completed Application may be submitted 

by (i) transmitting the required information to the Transmission Provider by 

telefax, or (ii) providing the information by telephone over the Transmission 

Provider's time recorded telephone line. Each of these methods will provide a 

time-stamped record for establishing the priority of the Application. 

17.2 Completed Application: 

A Completed Application shall provide all of the information included in 18 

CFR  2.20 including but not limited to the following: 

(i) The identity, address, telephone number and facsimile number of 

the entity requesting service; 

(ii) A statement that the entity requesting service is, or will be upon 

commencement of service, an Eligible Customer under the Tariff; 

(iii) The location of the Point(s) of Receipt and Point(s) of Delivery 

and the identities of the Delivering Parties and the Receiving 

Parties; 

(iv) The location of the generating facility(ies) supplying the capacity 

and energy and the location of the load ultimately served by the 
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capacity and energy transmitted. The Transmission Provider will 

treat this information as confidential except to the extent that 

disclosure of this information is required by this Tariff, by 

regulatory or judicial order, for reliability purposes pursuant to 

Good Utility Practice or pursuant to RTG transmission 

information sharing agreements. The Transmission Provider shall 

treat this information consistent with the standards of conduct 

contained in Part 37 of the Commission's regulations; 

(v) A description of the supply characteristics of the capacity and 

energy to be delivered; 

(vi) An estimate of the capacity and energy expected to be delivered 

to the Receiving Party; 

(vii) The Service Commencement Date and the term of the requested 

Transmission Service; 

(viii) The transmission capacity requested for each Point of Receipt and 

each Point of Delivery on the Transmission Provider's 

Transmission System; customers may combine their requests for 

service in order to satisfy the minimum transmission capacity 

requirement; 

(ix) A statement indicating that, if the Eligible Customer submits a 
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Original Sheet No. 68 

Pre-Confirmed Application, the Eligible Customer will execute a 

Service Agreement upon receipt of notification that the 

Transmission Provider can provide the requested Transmission 

Service; and 

(x) Any additional information required by the Transmission 

Provider’s planning process established in Attachment K. 

The Transmission Provider shall treat this information consistent with the 

standards of conduct contained in Part 37 of the Commission's regulations. 

17.3 Deposit: 

A Completed Application for Firm Point-To-Point Transmission Service also 

shall include a deposit of either one month's charge for Reserved Capacity or 

the full charge for Reserved Capacity for service requests of less than one 

month. If the Application is rejected by the Transmission Provider because it 

does not meet the conditions for service as set forth herein, or in the case of 

requests for service arising in connection with losing bidders in a Request For 

Proposals (RFP), said deposit shall be returned with interest less any 

reasonable costs incurred by the Transmission Provider in connection with the 

review of the losing bidder's Application. The deposit also will be returned 

with interest less any reasonable costs incurred by the Transmission Provider 

if the Transmission Provider is unable to complete new facilities needed to 
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Original Sheet No. 69 

provide the service. If an Application is withdrawn or the Eligible Customer 

decides not to enter into a Service Agreement for Firm Point-To-Point 

Transmission Service, the deposit shall be refunded in full, with interest, less 

reasonable costs incurred by the Transmission Provider to the extent such 

costs have not already been recovered by the Transmission Provider from the 

Eligible Customer. The Transmission Provider will provide to the Eligible 

Customer a complete accounting of all costs deducted from the refunded 

deposit, which the Eligible Customer may contest if there is a dispute 

concerning the deducted costs. Deposits associated with construction of new 

facilities are subject to the provisions of Section 19. If a Service Agreement 

for Firm Point-To-Point Transmission Service is executed, the deposit, with 

interest, will be returned to the Transmission Customer upon expiration or 

termination of the Service Agreement for Firm Point-To-Point Transmission 

Service. Applicable interest shall be computed in accordance with the 

Commission's regulations at 18 CFR  35.19a(a)(2)(iii), and shall be calculated 

from the day the deposit check is credited to the Transmission Provider's 

account. 

17.4 Notice of Deficient Application: 

If an Application fails to meet the requirements of the Tariff, the Transmission 

Provider shall notify the entity requesting service within fifteen (15) days of 
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Original Sheet No. 70 

receipt of the reasons for such failure. The Transmission Provider will 

attempt to remedy minor deficiencies in the Application through informal 

communications with the Eligible Customer. If such efforts are unsuccessful, 

the Transmission Provider shall return the Application, along with any 

deposit, with interest. Upon receipt of a new or revised Application that fully 

complies with the requirements of Part II of the Tariff, the Eligible Customer 

shall be assigned a new priority consistent with the date of the new or revised 

Application. 

17.5 Response to a Completed Application: 

Following receipt of a Completed Application for Firm Point-To-Point 

Transmission Service, the Transmission Provider shall make a determination 

of available transfer capability as required in Section 15.2. The Transmission 

Provider shall notify the Eligible Customer as soon as practicable, but not later 

than thirty (30) days after the date of receipt of a Completed Application 

either (i) if it will be able to provide service without performing a System 

Impact Study or (ii) if such a study is needed to evaluate the impact of the 

Application pursuant to Section 19.1. Responses by the Transmission 

Provider must be made as soon as practicable to all completed applications 

(including applications by its own merchant function) and the timing of such 

responses must be made on a non-discriminatory basis. 
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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, subject to availability, 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-month's charge for Firm Transmission Service for 

each year or fraction thereof within 15 days of notifying the Transmission 

Provider it intends to extend the commencement of service. If during any 
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Original Sheet No. 72 

extension for the commencement of service an Eligible Customer submits a 

Completed Application for Firm Transmission Service, and such request can 

be satisfied only by releasing all or part of the Transmission Customer's 

Reserved Capacity, the original Reserved Capacity will be released unless the 

following condition is satisfied. Within thirty (30) days, the original 

Transmission Customer agrees to pay the Firm Point-To-Point transmission 

rate for its Reserved Capacity concurrent with the new Service 

Commencement Date. In the event the Transmission Customer elects to 

release the Reserved Capacity, the reservation fees or portions thereof 

previously paid will be forfeited. 

18 Procedures for Arranging Non-Firm Point-To-Point Transmission 

Service 

18.1 Application: 

Eligible Customers seeking Non-Firm Point-To-Point Transmission Service 

must submit a Completed Application to the Transmission Provider. 

Applications should be submitted by entering the information listed below on 

the Transmission Provider's OASIS. Prior to implementation of the 

Transmission Provider's OASIS, a Completed Application may be submitted 

by (i) transmitting the required information to the Transmission Provider by 

telefax, or (ii) providing the information by telephone over the Transmission 
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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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Original Sheet No. 74 

(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 that, if the Eligible Customer submits a 

Pre-Confirmed Application, the Eligible Customer 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 
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Original Sheet No. 75 

received later than 2:00 p.m. prior to the day service is scheduled to 

commence will be accommodated if practicable [or such reasonable times that 

are generally accepted in the region and are consistently adhered to by the 

Transmission Provider]. 

18.4 Determination of Available Transfer Capability: 

Following receipt of a tendered schedule the Transmission Provider will make 

a determination on a non-discriminatory basis of available transfer capability 

pursuant to Section 15.2. Such determination shall be made as soon as 

reasonably practicable after receipt, but not later than the following time 

periods for the following terms of service (i) thirty (30) minutes for hourly 

service, (ii) thirty (30) minutes for daily service, (iii) four (4) hours for weekly 

service, and (iv) two (2) days for monthly service. [Or such reasonable times 

that are generally accepted in the region and are consistently adhered to by the 

Transmission Provider]. 

19 Additional Study Procedures For Firm Point-To-Point Transmission 

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 
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Original Sheet No. 76 

Transmission Provider determines that a System Impact Study is necessary to 

accommodate the requested service, it shall so inform the Eligible Customer, 

as soon as practicable. Once informed, the Eligible Customer shall timely 

notify the Transmission Provider if it elects to have the Transmission Provider 

study redispatch or conditional curtailment as part of the System Impact 

Study. If notification is provided prior to tender of the System Impact Study 

Agreement, the Eligible Customer can avoid the costs associated with the 

study of these options. The Transmission Provider shall within thirty (30) days 

of receipt of a Completed Application, tender a System Impact Study 

Agreement pursuant to which the Eligible Customer shall agree to reimburse 

the Transmission Provider for performing the required System Impact Study. 

For a service request to remain a Completed Application, the Eligible 

Customer shall execute the System Impact Study Agreement and return it to 

the Transmission Provider within fifteen (15) days. If the Eligible Customer 

elects not to execute the System Impact Study Agreement, its application shall 

be deemed withdrawn and its deposit, pursuant to Section 17.3, shall be 

returned with interest. 

19.2 System Impact Study Agreement and Cost Reimbursement: 

 

(i) The System Impact Study Agreement will clearly specify the 

Transmission Provider's estimate of the actual cost, and time for 
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Original Sheet No. 77 

completion of the System Impact Study. The charge shall not 

exceed the actual cost of the study. In performing the System 

Impact Study, the Transmission Provider shall rely, to the extent 

reasonably practicable, on existing transmission planning studies. 

The Eligible Customer will not be assessed a charge for such 

existing studies; however, the Eligible Customer will be 

responsible for charges associated with any modifications to 

existing planning studies that are reasonably necessary to evaluate 

the impact of the Eligible Customer's request for service on the 

Transmission System. 

(ii) If in response to multiple Eligible Customers requesting service in 

relation to the same competitive solicitation, a single System 

Impact Study is sufficient for the Transmission Provider to 

accommodate the requests for service, the costs of that study shall 

be pro-rated among the Eligible Customers. 

(iii) For System Impact Studies that the Transmission Provider 

conducts on its own behalf, the Transmission Provider shall 

record the cost of the System Impact Studies pursuant to Section 

20. 

19.3 System Impact Study Procedures: 
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Original Sheet No. 78 

Upon receipt of an executed System Impact Study Agreement, the 

Transmission Provider will use due diligence to complete the required System 

Impact Study within a sixty (60) day period. The System Impact Study shall 

identify (1) any system constraints, identified with specificity by transmission 

element or flowgate, (2) redispatch options (when requested by an Eligible 

Customer) including an estimate of the cost of redispatch, (3) conditional 

curtailment options (when requested by an Eligible Customer) including the 

number of hours per year and the System Conditions during which conditional 

curtailment may occur, and (4) additional Direct Assignment Facilities or 

Network Upgrades required to provide the requested service. For customers 

requesting the study of redispatch options, the System Impact Study shall (1) 

identify all resources located within the Transmission Provider’s Control Area 

that can significantly contribute toward relieving the system constraint and (2) 

provide a measurement of each resource’s impact on the system constraint. If 

the Transmission Provider possesses information indicating that any resource 

outside its Control Area could relieve the constraint, it shall identify each such 

resource in the System Impact Study. In the event that the Transmission 

Provider is unable to complete the required System Impact Study within such 

time period, it shall so notify the Eligible Customer and provide an estimated 

completion date along with an explanation of the reasons why additional time 
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Original Sheet No. 79 

is required to complete the required studies. A copy of the completed System 

Impact Study and related work papers shall be made available to the Eligible 

Customer as soon as the System Impact Study is complete. The Transmission 

Provider will use the same due diligence in completing the System Impact 

Study for an Eligible Customer as it uses when completing studies for itself. 

The Transmission Provider shall notify the Eligible Customer immediately 

upon completion of the System Impact Study if the Transmission System will 

be adequate to accommodate all or part of a request for service or that no costs 

are likely to be incurred for new transmission facilities or upgrades. In order 

for a request to remain a Completed Application, within fifteen (15) days of 

completion of the System Impact Study the Eligible Customer must execute a 

Service Agreement or request the filing of an unexecuted Service Agreement 

pursuant to Section 15.3, or the Application shall be deemed terminated and 

withdrawn. 

19.4 Facilities Study Procedures: 

If a System Impact Study indicates that additions or upgrades to the 

Transmission System are needed to supply the Eligible Customer's service 

request, the Transmission Provider, within thirty (30) days of the completion 

of the System Impact Study, shall tender to the Eligible Customer a Facilities 

Study Agreement pursuant to which the Eligible Customer shall agree to 
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reimburse the Transmission Provider for performing the required Facilities 

Study. For a service request to remain a Completed Application, the Eligible 

Customer shall execute the Facilities Study Agreement and return it to the 

Transmission Provider within fifteen (15) days. If the Eligible Customer 

elects not to execute the Facilities Study Agreement, its application shall be 

deemed withdrawn and its deposit, pursuant to Section 17.3, shall be returned 

with interest. Upon receipt of an executed Facilities Study Agreement, the 

Transmission Provider will use due diligence to complete the required 

Facilities Study within a sixty (60) day period. If the Transmission Provider is 

unable to complete the Facilities Study in the allotted time period, the 

Transmission Provider shall notify the Transmission Customer and provide an 

estimate of the time needed to reach a final determination along with an 

explanation of the reasons that additional time is required to complete the 

study. When completed, the Facilities Study will include a good faith estimate 

of (i) the cost of Direct Assignment Facilities to be charged to the 

Transmission Customer, (ii) the Transmission Customer's appropriate share of 

the cost of any required 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 
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Original Sheet No. 81 

reasonable form of security acceptable to the Transmission Provider 

equivalent to the costs of new facilities or upgrades consistent with 

commercial practices as established by the Uniform Commercial Code. The 

Transmission Customer shall have thirty (30) days to execute a Service 

Agreement or request the filing of an unexecuted Service Agreement and 

provide the required letter of credit or other form of security or the request 

will no longer be a Completed Application and shall be deemed terminated 

and withdrawn. 

19.5 Facilities Study Modifications: 

Any change in design arising from inability to site or construct facilities as 

proposed will require development of a revised good faith estimate. New 

good faith estimates also will be required in the event of new statutory or 

regulatory requirements that are effective before the completion of 

construction or other circumstances beyond the control of the Transmission 

Provider that significantly affect the final cost of new facilities or upgrades to 

be charged to the Transmission Customer pursuant to the provisions of Part II 

of the Tariff. 

19.6 Due Diligence in Completing New Facilities: 

The Transmission Provider shall use due diligence to add necessary facilities 

or upgrade its Transmission System within a reasonable time. The 
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Original Sheet No. 82 

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: 

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 
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compensate the Transmission Provider for all costs incurred pursuant to the 

terms of the Tariff. In order to exercise this option, the Eligible Customer 

shall request in writing an expedited Service Agreement covering all of the 

above-specified items within thirty (30) days of receiving the results of the 

System Impact Study identifying needed facility additions or upgrades or costs 

incurred in providing the requested service. While the Transmission Provider 

agrees to provide the Eligible Customer with its best estimate of the new 

facility costs and other charges that may be incurred, such estimate shall not 

be binding and the Eligible Customer must agree in writing to compensate the 

Transmission Provider for all costs incurred pursuant to the provisions of the 

Tariff. The Eligible Customer shall execute and return such an Expedited 

Service Agreement within fifteen (15) days of its receipt or the Eligible 

Customer's request for service will cease to be a Completed Application and 

will be deemed terminated and withdrawn. 

19.9 Penalties for Failure to Meet Study Deadlines: 

Sections 19.3 and 19.4 require a Transmission Provider to use due diligence to 

meet 60-day study completion deadlines for System Impact Studies and 

Facilities Studies. 

(i) The Transmission Provider is required to file a notice with the 

Commission in the event that more than twenty (20) percent of 
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non-Affiliates’ System Impact Studies and Facilities Studies 

completed by the Transmission Provider in any two consecutive 

calendar quarters are not completed within the 60-day study 

completion deadlines. Such notice must be filed within thirty (30) 

days of the end of the calendar quarter triggering the notice 

requirement. 

(ii) For the purposes of calculating the percent of non-Affiliates’ 

System Impact Studies and Facilities Studies processed outside of 

the 60-day study completion deadlines, the Transmission Provider 

shall consider all System Impact Studies and Facilities Studies 

that it completes for non-Affiliates during the calendar quarter. 

The percentage should be calculated by dividing the number of 

those studies which are completed on time by the total number of 

completed studies. The Transmission Provider may provide an 

explanation in its notification filing to the Commission if it 

believes there are extenuating circumstances that prevented it 

from meeting the 60-day study completion deadlines. 

(iii) The Transmission Provider is subject to an operational penalty if 

it completes ten (10) percent or more of non-Affiliates’ System 

Impact Studies and Facilities Studies outside of the 60-day study 
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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. 

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 
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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 

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 
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Provider concludes that no reasonable alternative exists and the Transmission 

Customer disagrees, the Transmission Customer may seek relief under the 

dispute resolution procedures pursuant to Section 12 or it may refer the 

dispute to the Commission for resolution. 

20.3 Refund Obligation for Unfinished Facility Additions: 

If the Transmission Provider and the Transmission Customer mutually agree 

that no other reasonable alternatives exist and the requested service cannot be 

provided out of existing capability under the conditions of Part II of the Tariff, 

the obligation to provide the requested Firm Point-To-Point Transmission 

Service shall terminate and any deposit made by the Transmission Customer 

shall be returned with interest pursuant to Commission regulations 

35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible 

for all prudently incurred costs by the Transmission Provider through the time 

construction was suspended. 

21 Provisions Relating to Transmission Construction and Services on the 

Systems of Other Utilities 

21.1 Responsibility for Third-Party System Additions: 

The Transmission Provider shall not be responsible for making arrangements 

for any necessary engineering, permitting, and construction of transmission or 

distribution facilities on the system(s) of any other entity or for obtaining any 

regulatory approval for such facilities. The Transmission Provider will 
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undertake reasonable efforts to assist the Transmission Customer in obtaining 

such arrangements, including without limitation, providing any information or 

data required by such other electric system pursuant to Good Utility Practice. 

21.2 Coordination of Third-Party System Additions: 

In circumstances where the need for transmission facilities or upgrades is 

identified pursuant to the provisions of Part II of the Tariff, and if such 

upgrades further require the addition of transmission facilities on other 

systems, the Transmission Provider shall have the right to coordinate 

construction on its own system with the construction required by others. The 

Transmission Provider, after consultation with the Transmission Customer and 

representatives of such other systems, may defer construction of its new 

transmission facilities, if the new transmission facilities on another system 

cannot be completed in a timely manner. The Transmission Provider shall 

notify the Transmission Customer in writing of the basis for any decision to 

defer construction and the specific problems which must be resolved before it 

will initiate or resume construction of new facilities. Within sixty (60) days of 

receiving written notification by the Transmission Provider of its intent to 

defer construction pursuant to this section, the Transmission Customer may 

challenge the decision in accordance with the dispute resolution procedures 
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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 

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 
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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 

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 
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priority for service at the existing firm Receipt and Delivery Points specified 

in its Service Agreement. 

23 Sale or Assignment of Transmission Service 

23.1 Procedures for Assignment or Transfer of Service: 

Subject to Commission approval of any necessary filings, a Transmission 

Customer may sell, assign, or transfer all or a portion of its rights under its 

Service Agreement, but only to another Eligible Customer (the Assignee). 

The Transmission Customer that sells, assigns or transfers its rights under its 

Service Agreement is hereafter referred to as the Reseller. Compensation to 

Resellers shall 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; provided that, for service prior to 

October 1, 2010, compensation to Resellers shall be at rates established by 

agreement between the Reseller and the Assignee. 

The Assignee must execute a service agreement with the Transmission 

Provider governing reassignments of transmission service prior to the date on 

which the reassigned service commences. The Transmission Provider shall 

charge the Reseller, as appropriate, at the rate stated in the Reseller’s Service 

Agreement with the Transmission Provider or the associated OASIS schedule 
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and credit the Reseller with the price reflected in the Assignee’s Service 

Agreement with the Transmission Provider or the associated OASIS schedule; 

provided that, such credit shall be reversed in the event of non-payment by 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 

set forth in the original Service Agreement, the Assignee will receive the same 

services as did the Reseller and the priority of service for the Assignee will be 

the same as that of the Reseller. The Assignee will be subject to all terms and 

conditions of this Tariff. If the Assignee requests a change in service, the 

reservation priority of service will be determined by the Transmission 

Provider pursuant to Section 13.2. 

23.2 Limitations on Assignment or Transfer of Service: 

If the Assignee requests a change in the Point(s) of Receipt or Point(s) of 

Delivery, or a change in any other specifications set forth in the original 

Service Agreement, the Transmission Provider will consent to such change 

subject to the provisions of the Tariff, provided that the change will not impair 

the operation and reliability of the Transmission Provider's generation, 

transmission, or distribution systems. The Assignee shall compensate the 

Transmission Provider for performing any System Impact Study needed to 

evaluate the capability of the Transmission System to accommodate the 
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proposed change and any additional costs resulting from such change. The 

Reseller shall remain liable for the performance of all obligations under the 

Service Agreement, except as specifically agreed to by the Transmission 

Provider and the Reseller through an amendment to the Service Agreement. 

23.3 Information on Assignment or Transfer of Service: 

In accordance with Section 4, all sales or assignments of capacity must be 

conducted through or otherwise posted on the Transmission Provider’s OASIS 

on or before the date the reassigned service commences and are subject to 

Section 23.1. Resellers may also use the Transmission Provider's OASIS to 

post transmission capacity available for resale. 

24 Metering and Power Factor Correction at Receipt and Delivery Points(s) 

24.1 Transmission Customer Obligations: 

Unless otherwise agreed, the Transmission Customer shall be responsible for 

installing and maintaining compatible metering and communications 

equipment to accurately account for the capacity and energy being transmitted 

under Part II of the Tariff and to communicate the information to the 

Transmission Provider. Such equipment shall remain the property of the 

Transmission Customer. 
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24.2 Transmission Provider Access to Metering Data: 

The Transmission Provider shall have access to metering data, which may 

reasonably be required to facilitate measurements and billing under the 

Service Agreement. 

24.3 Power Factor: 

Unless otherwise agreed, the Transmission Customer is required to maintain a 

power factor within the same range as the Transmission Provider pursuant to 

Good Utility Practices. The power factor requirements are specified in the 

Service Agreement where applicable. 

25 Compensation for Transmission Service 

 Rates for Firm and Non-Firm 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 
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Transmission Provider must separately file any specific proposed stranded cost 

charge under Section 205 of the Federal Power Act. 

27 Compensation for New Facilities and Redispatch Costs 

 Whenever a System Impact Study performed by the Transmission Provider 

in connection with the provision of Firm Point-To-Point Transmission Service 

identifies the need for new facilities, the Transmission Customer shall be 

responsible for such costs to the extent consistent with Commission policy. 

Whenever a System Impact Study performed by the Transmission Provider 

identifies capacity constraints that may be relieved by redispatching the 

Transmission Provider's resources to eliminate such constraints, the Transmission 

Customer shall be responsible for the redispatch costs to the extent consistent with 

Commission policy. 

III. NETWORK INTEGRATION TRANSMISSION SERVICE

Preamble 

 The Transmission Provider will provide Network Integration Transmission 

Service pursuant to the applicable terms and conditions contained in the Tariff and 

Service Agreement. Network Integration Transmission Service allows the Network 

Customer to integrate, economically dispatch and regulate its current and planned 

Network Resources to serve its Network Load in a manner comparable to that in which 

the Transmission Provider utilizes its Transmission System to serve its Native Load 
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Customers. Network Integration Transmission Service also may be used by the Network 

Customer to deliver economy energy purchases to its Network Load from non-designated 

resources on an as-available basis without additional charge. Transmission service for 

sales to non-designated loads will be provided pursuant to the applicable terms and 

conditions of Part II of the Tariff. 

28 Nature of Network Integration Transmission Service 

28.1 Scope of Service: 

Network Integration Transmission Service is a transmission service that 

allows Network Customers to efficiently and economically utilize their 

Network Resources (as well as other 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, 
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on behalf of its Native Load Customers, shall be required to designate 

resources and loads in the same manner as any Network Customer under Part 

III of this Tariff. This information must be consistent with the information 

used by the Transmission Provider to calculate available transfer capability. 

The Transmission Provider shall include the Network Customer's Network 

Load in its Transmission System planning and shall, consistent with Good 

Utility Practice and Attachment K, endeavor to construct and place into 

service sufficient transfer capability to deliver the Network Customer's 

Network Resources to serve its Network Load on a basis comparable to the 

Transmission Provider's delivery of its own generating and purchased 

resources to its Native Load Customers. 

28.3 Network Integration Transmission Service: 

The Transmission Provider will provide firm transmission service over its 

Transmission System to the Network Customer for the delivery of capacity 

and energy from its designated Network Resources to service its Network 

Loads on a basis that is comparable to the Transmission Provider's use of the 

Transmission System to reliably serve its Native Load Customers. 

28.4 Secondary Service: 

The Network Customer may use the Transmission Provider's Transmission 

System to deliver energy to its Network Loads from resources that have not 
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been designated as Network Resources. Such energy shall be transmitted, on 

an as-available basis, at no additional charge. Secondary service shall not 

require the filing of an Application for Network Integration Transmission 

Service under the Tariff. However, all other requirements of Part III of the 

Tariff (except for transmission rates) shall apply to secondary service. 

Deliveries from resources other than Network Resources will have a higher 

priority than any Non-Firm Point-To-Point Transmission Service under Part II 

of the Tariff. 

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 
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Transmission Service shall use Point-To-Point Transmission Service under 

Part II of the Tariff for any Third-Party Sale which requires use of the 

Transmission Provider's Transmission System. The Transmission Provider 

shall specify any appropriate charges and penalties and all related terms and 

conditions applicable in the event that a Network Customer uses Network 

Integration Transmission Service or secondary service pursuant to Section 

28.4 to facilitate a wholesale sale that does not serve a Network Load. 

29 Initiating Service 

29.1 Condition Precedent for Receiving Service: 

Subject to the terms and conditions of Part III of the Tariff, the Transmission 

Provider will provide Network Integration Transmission Service to any 

Eligible Customer, provided that (i) the Eligible Customer completes an 

Application for service as provided under Part III of the Tariff, (ii) the Eligible 

Customer and the Transmission Provider complete the technical arrangements 

set forth in Sections 29.3 and 29.4, (iii) the Eligible Customer executes a 

Service Agreement pursuant to Attachment F for service under Part III of the 

Tariff or requests in writing that the Transmission Provider file a proposed 

unexecuted Service Agreement with the Commission, and (iv) the Eligible 

Customer executes a Network Operating Agreement with the Transmission 

Provider pursuant to Attachment G, or requests in writing that the 
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Transmission Provider file a proposed unexecuted Network Operating 

Agreement. 

29.2 Application Procedures: 

An Eligible Customer requesting service under Part III of the Tariff must 

submit an Application, with a deposit approximating the charge for one month 

of service, to the Transmission Provider as far as possible in advance of the 

month in which service is to commence. Unless subject to the procedures in 

Section 2, Completed Applications for Network Integration Transmission 

Service will be assigned a priority according to the date and time the 

Application is received, with the earliest Application receiving the highest 

priority. Applications should be submitted by entering the information listed 

below on the Transmission Provider's OASIS. Prior to implementation of the 

Transmission Provider's OASIS, a Completed Application may be submitted 

by (i) transmitting the required information to the Transmission Provider by 

telefax, or (ii) providing the information by telephone over the Transmission 

Provider's time recorded telephone line. Each of these methods will provide a 

time-stamped record for establishing the service priority of the Application. A 

Completed Application shall provide all of the information included in 18 

CFR § 2.20 including but not limited to the following: 
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(i) The identity, address, telephone number and facsimile number of 

the party requesting service; 

(ii) A statement that the party requesting service is, or will be upon 

commencement of service, an Eligible Customer under the Tariff; 

(iii) A description of the Network Load at each delivery point. This 

description should separately identify and provide the Eligible 

Customer's best estimate of the total loads to be served at each 

transmission voltage level, and the loads to be served from each 

Transmission Provider substation at the same transmission 

voltage level. The description should include a ten (10) year 

forecast of summer and winter load and resource requirements 

beginning with the first year after the service is scheduled to 

commence; 

(iv) The amount and location of any interruptible loads included in the 

Network Load. This shall include the summer and winter 

capacity requirements for each interruptible load (had such load 

not been interruptible), that portion of the load subject to 

interruption, the conditions under which an interruption can be 

implemented and any limitations on the amount and frequency of 

interruptions. An Eligible Customer should identify the amount 
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of interruptible customer load (if any) included in the 10 year load 

forecast provided in response to (iii) above; 

(v) A description of Network Resources (current and 10-year 

projection). For each on-system Network Resource, such 

description shall include: 

• Unit size and amount of capacity from that unit to be 

designated as Network Resource 

• VAR capability (both leading and lagging) of all generators 

• Operating restrictions 

− Any periods of restricted operations throughout the year 

− Maintenance schedules 

− Minimum loading level of unit 

− Normal operating level of unit 

− Any must-run unit designations required for system 

reliability or contract reasons 

• Approximate variable generating cost ($/MWH) for 

redispatch computations 

• Arrangements governing sale and delivery of power to third 

parties from generating facilities located in the Transmission 
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Provider Control Area, where only a portion of unit output is 

designated as a Network Resource; 

For each off-system Network Resource, such description shall 

include: 

• Identification of the Network Resource as an off-system 

resource 

• Amount of power to which the customer has rights 

• Identification of the control area from which the power will 

originate 

• Delivery point(s) to the Transmission Provider’s 

Transmission System 

• Transmission arrangements on the external transmission 

system(s) 

• Operating restrictions, if any 

− Any periods of restricted operations throughout the year 

− Maintenance schedules 

− Minimum loading level of unit 

− Normal operating level of unit 

− Any must-run unit designations required for system 

reliability or contract reasons 
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• Approximate variable generating cost ($/MWH) for 

redispatch computations; 

(vi) Description of Eligible Customer's transmission system: 

• Load flow and stability data, such as real and reactive parts of 

the load, lines, transformers, reactive devices and load type, 

including normal and emergency ratings of all transmission 

equipment in a load flow format compatible with that used by 

the Transmission Provider 

• Operating restrictions needed for reliability 

• Operating guides employed by system operators 

• Contractual restrictions or committed uses of the Eligible 

Customer's transmission system, other than the Eligible 

Customer's Network Loads and Resources 

• Location of Network Resources described in subsection (v) 

above 

• 10 year projection of system expansions or upgrades 

• Transmission System maps that include any proposed 

expansions or upgrades 

• Thermal ratings of Eligible Customer's Control Area ties with 

other Control Areas; 
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(vii) Service Commencement Date and the term of the requested 

Network Integration Transmission Service. The minimum term 

for Network Integration Transmission Service is one year; 

(viii) A statement signed by an authorized officer from or agent of the 

Network Customer attesting that all of the network resources 

listed pursuant to Section 29.2(v) satisfy the following conditions: 

(1) the Network Customer owns the resource, has committed to 

purchase generation pursuant to an executed contract, or has 

committed to purchase generation where execution of a contract is 

contingent upon the availability of transmission service under Part 

III of the Tariff; and (2) the Network Resources do not include 

any resources, or any portion thereof, that are committed for sale 

to non-designated third party load or otherwise cannot be called 

upon to meet the Network Customer's Network Load on a noninterruptible basis; and 

(ix) Any additional information required of the Transmission 

Customer as specified in the Transmission Provider’s planning 

process established in Attachment K. 

Unless the Parties agree to a different time frame, the Transmission Provider 

must acknowledge the request within ten (10) days of receipt. The 
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acknowledgement must include a date by which a response, including a 

Service Agreement, will be sent to the Eligible Customer. If an Application 

fails to meet the requirements of this section, the Transmission Provider shall 

notify the Eligible Customer requesting service within fifteen (15) days of 

receipt and specify the reasons for such failure. Wherever possible, the 

Transmission Provider will attempt to remedy deficiencies in the Application 

through informal communications with the Eligible Customer. If such efforts 

are unsuccessful, the Transmission Provider shall return the Application 

without prejudice to the Eligible Customer filing a new or revised Application 

that fully complies with the requirements of this section. The Eligible 

Customer will be assigned a new priority consistent with the date of the new 

or revised Application. The Transmission Provider shall treat this information 

consistent with the standards of conduct contained in Part 37 of the 

Commission's regulations. 

29.3 Technical Arrangements to be Completed Prior to Commencement 

of Service: 

Network Integration Transmission Service shall not commence until the 

Transmission Provider and the Network Customer, or a third party, have 

completed installation of all equipment specified under the Network Operating 

Agreement consistent with Good Utility Practice and any additional 
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requirements reasonably and consistently imposed to ensure the reliable 

operation of the Transmission System. The Transmission Provider shall 

exercise reasonable efforts, in coordination with the Network Customer, to 

complete such arrangements as soon as practicable taking into consideration 

the Service Commencement Date. 

29.4 Network Customer Facilities: 

The provision of Network Integration Transmission Service shall be 

conditioned upon the Network Customer's constructing, maintaining and 

operating the facilities on its side of each delivery point or interconnection 

necessary to reliably deliver capacity and energy from the Transmission 

Provider's Transmission System to the Network Customer. The Network 

Customer shall be solely responsible for constructing or installing all facilities 

on the Network Customer's side of each such delivery point or 

interconnection. 

29.5 Filing of Service Agreement: 

The Transmission Provider will file Service Agreements with the Commission 

in compliance with applicable Commission regulations. 

 
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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: 

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 
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generation pursuant to an executed contract, or has committed to purchase 

generation where execution of a contract is contingent upon the availability of 

transmission service under Part III of the Tariff; and (2) The Network 

Resources do not include any resources, or any portion thereof, that are 

committed for sale to non-designated third party load or otherwise cannot be 

called upon to meet the Network Customer's Network Load on a noninterruptible basis. The Network Customer’s request will be deemed deficient 

if it does not include this statement and the Transmission Provider will follow 

the procedures for a deficient application as described in Section 29.2 of the 

Tariff. 

30.3 Termination of Network Resources: 

The Network Customer may terminate the designation of all or part of a 

generating resource as a Network Resource by providing notification to the 

Transmission Provider through OASIS as soon as reasonably practicable, but 

not later than the firm scheduling deadline for the period of termination. Any 

request for termination of Network Resource status must be submitted on 

OASIS, and should indicate whether the request is for indefinite or temporary 

termination. A request for indefinite termination of Network Resource status 

must indicate the date and time that the termination is to be effective, and the 

identification and capacity of the resource(s) or portions thereof to be 
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indefinitely terminated. A request for temporary termination of Network 

Resource status must include the following: 

(i) Effective date and time of temporary termination; 

(ii) Effective date and time of redesignation, following period of 

temporary termination; 

(iii) Identification and capacity of resource(s) or portions thereof to be 

temporarily terminated; 

(iv) Resource description and attestation for redesignating the network 

resource following the temporary termination, in accordance with 

Section 30.2; and 

(v) Identification of any related transmission service requests to be 

evaluated concomitantly with the request for temporary 

termination, such that the requests for undesignation and the 

request for these related transmission service requests must be 

approved or denied as a single request. The evaluation of these 

related transmission service requests must take into account the 

termination of the network resources identified in (iii) above, as 

well as all competing transmission service requests of higher 

priority. 
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As part of a temporary termination, a Network Customer may only redesignate 

the same resource that was originally designated, or a portion thereof. 

Requests to redesignate a different resource and/or a resource with increased 

capacity will be deemed deficient and the Transmission Provider will follow 

the procedures for a deficient application as described in Section 29.2 of the 

Tariff. 

30.4 Operation of Network Resources: 

The Network Customer shall not operate its designated Network Resources 

located in the Network Customer's or Transmission Provider's Control Area 

such that the output of those facilities exceeds its designated Network Load, 

plus Non-Firm Sales delivered pursuant to Part II of the Tariff, plus losses, 

plus power sales under a Commission-approved reserve sharing program. 

This limitation shall not apply to changes in the operation of a Transmission 

Customer's Network Resources at the request of the Transmission Provider to 

respond to an emergency or other unforeseen condition which may impair or 

degrade the reliability of the Transmission System. For all Network 

Resources not physically connected with the Transmission Provider’s 

Transmission System, the Network Customer may not schedule delivery of 

energy in excess of the Network Resource’s capacity, as specified in the 

Network Customer’s Application pursuant to Section 29, unless the Network 
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Customer supports such delivery within the Transmission Provider’s 

Transmission System by either obtaining Point-to-Point Transmission Service 

or utilizing secondary service pursuant to Section 28.4. The Transmission 

Provider shall specify the rate treatment and all related terms and conditions 

applicable in the event that a Network Customer’s schedule at the delivery 

point for a Network Resource not physically interconnected with the 

Transmission Provider's Transmission System exceeds the Network 

Resource’s designated capacity, excluding energy delivered using secondary 

service or Point-to-Point Transmission Service. 

30.5 Network Customer Redispatch Obligation: 

As a condition to receiving Network Integration Transmission Service, the 

Network Customer agrees to redispatch its Network Resources as requested by 

the Transmission Provider pursuant to Section 33.2. To the extent practical, 

the redispatch of resources pursuant to this section shall be on a least cost, 

non-discriminatory basis between all Network Customers, and the 

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 
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interconnected with the Transmission Provider's Transmission System. The 

Transmission Provider will undertake reasonable efforts to assist the Network 

Customer in obtaining such arrangements, including without limitation, 

providing any information or data required by such other entity pursuant to 

Good Utility Practice. 

30.7 Limitation on Designation of Network Resources: 

The Network Customer must demonstrate that it owns or has committed to 

purchase generation pursuant to an executed contract in order to designate a 

generating resource as a Network Resource. Alternatively, the Network 

Customer may establish that execution of a contract is contingent upon the 

availability of transmission service under Part III of the Tariff. 

30.8 Use of Interface Capacity by the Network Customer: 

There is no limitation upon a Network Customer's use of the Transmission 

Provider's Transmission System at any particular interface to integrate the 

Network Customer's Network Resources (or substitute economy purchases) 

with its Network Loads. However, a Network Customer's use of the 

Transmission Provider's total interface capacity with other transmission 

systems may not exceed the Network Customer's Load. 

30.9 Network Customer Owned Transmission Facilities: 

The Network Customer that owns existing transmission facilities that are 
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integrated with the Transmission Provider's Transmission System may be 

eligible to receive consideration either through a billing credit or some other 

mechanism. In order to receive such consideration the Network Customer 

must demonstrate that its transmission facilities are integrated into the plans or 

operations of the Transmission Provider, to serve its power and transmission 

customers. For facilities added by the Network Customer subsequent to the 

[the effective date of a Final Rule in RM05-25-000], the Network Customer 

shall receive credit for such transmission facilities added if such facilities are 

integrated into the operations of the Transmission Provider’s facilities; 

provided however, the Network Customer’s transmission facilities shall be 

presumed to be integrated if such transmission facilities, if owned by the 

Transmission Provider, would be eligible for inclusion in the Transmission 

Provider’s annual transmission revenue requirement as specified in 

Attachment H. Calculation of any credit under this subsection shall be 

addressed in either the Network Customer's Service Agreement or any other 

agreement between the Parties. 

31 Designation of Network Load 

31.1 Network Load: 

The Network Customer must designate the individual Network Loads on 

whose behalf the Transmission Provider will provide Network Integration 
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Transmission Service. The Network Loads shall be specified in the Service 

Agreement. 

31.2 New Network Loads Connected With the Transmission Provider: 

The Network Customer shall provide the Transmission Provider with as much 

advance notice as reasonably practicable of the designation of new Network 

Load that will be added to its Transmission System. A designation of new 

Network Load must be made through a modification of service pursuant to a 

new Application. The Transmission Provider will use due diligence to install 

any transmission facilities required to interconnect a new Network Load 

designated by the Network Customer. The costs of new facilities required to 

interconnect a new Network Load shall be determined in accordance with the 

procedures provided in Section 32.4 and shall be charged to the Network 

Customer in accordance with Commission policies. 

31.3 Network Load Not Physically Interconnected with the Transmission 

Provider: 

This section applies to both initial designation pursuant to Section 31.1 and 

the subsequent addition of new Network Load not physically interconnected 

with the Transmission Provider. To the extent that the Network Customer 

desires to obtain transmission service for a load outside the Transmission 

Provider's Transmission System, the Network Customer shall have the option 
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of (1) electing to include the entire load as Network Load for all purposes 

under Part III of the Tariff and designating Network Resources in connection 

with such additional Network Load, or (2) excluding that entire load from its 

Network Load and purchasing Point-To-Point Transmission Service under 

Part II of the Tariff. To the extent that the Network Customer gives notice of 

its intent to add a new Network Load as part of its Network Load pursuant to 

this section the request must be made through a modification of service 

pursuant to a new Application. 

31.4 New Interconnection Points: 

To the extent the Network Customer desires to add a new Delivery Point or 

interconnection point between the Transmission Provider's Transmission 

System and a Network Load, the Network Customer shall provide the 

Transmission Provider with as much advance notice as reasonably practicable. 

31.5 Changes in Service Requests: 

Under no circumstances shall the Network Customer's decision to cancel or 

delay a requested change in Network Integration Transmission Service (e.g.

the addition of a new Network Resource or designation of a new Network 

Load) in any way relieve the Network Customer of its obligation to pay the 

costs of transmission facilities constructed by the Transmission Provider and 

charged to the Network Customer as reflected in the Service Agreement. 
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However, the Transmission Provider must treat any requested change in 

Network Integration Transmission Service in a non-discriminatory manner. 

31.6 Annual Load and Resource Information Updates: 

The Network Customer shall provide the Transmission Provider with annual 

updates of Network Load and Network Resource forecasts consistent with 

those included in its Application for Network Integration Transmission 

Service under Part III of the Tariff including, but not limited to, any 

information provided under section 29.2(ix) pursuant to the Transmission 

Provider’s planning process in Attachment K. The Network Customer also 

shall provide the Transmission Provider with timely written notice of material 

changes in any other information provided in its Application relating to the 

Network Customer's Network Load, Network Resources, its transmission 

system or other aspects of its facilities or operations affecting the 

Transmission Provider's ability to provide reliable service. 

32 Additional Study Procedures For Network Integration Transmission 

Service Requests 

32.1 Notice of Need for System Impact Study: 

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 
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Transmission Provider determines that a System Impact Study is necessary to 

accommodate the requested service, it shall so inform the Eligible Customer, 

as soon as practicable. In such cases, the Transmission Provider shall within 

thirty (30) days of receipt of a Completed Application, tender a System Impact 

Study Agreement pursuant to which the Eligible Customer shall agree to 

reimburse the Transmission Provider for performing the required System 

Impact Study. For a service request to remain a Completed Application, the 

Eligible Customer shall execute the System Impact Study Agreement and 

return it to the Transmission Provider within fifteen (15) days. If the Eligible 

Customer elects not to execute the System Impact Study Agreement, its 

Application shall be deemed withdrawn and its deposit shall be returned with 

interest. 

32.2 System Impact Study Agreement and Cost Reimbursement: 

(i) The System Impact Study Agreement will clearly specify the 

Transmission Provider's estimate of the actual cost, and time for 

completion of the System Impact Study. The charge shall not 

exceed the actual cost of the study. In performing the System 

Impact Study, the Transmission Provider shall rely, to the extent 

reasonably practicable, on existing transmission planning studies. 

The Eligible Customer will not be assessed a charge for such 
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existing studies; however, the Eligible Customer will be 

responsible for charges associated with any modifications to 

existing planning studies that are reasonably necessary to evaluate 

the impact of the Eligible Customer's request for service on the 

Transmission System. 

(ii) If in response to multiple Eligible Customers requesting service in 

relation to the same competitive solicitation, a single System 

Impact Study is sufficient for the Transmission Provider to 

accommodate the service requests, the costs of that study shall be 

pro-rated among the Eligible Customers. 

(iii) For System Impact Studies that the Transmission Provider 

conducts on its own behalf, the Transmission Provider shall 

record the cost of the System Impact Studies pursuant to Section 

8. 

32.3 System Impact Study Procedures: 

Upon receipt of an executed System Impact Study Agreement, the 

Transmission Provider will use due diligence to complete the required System 

Impact Study within a sixty (60) day period. The System Impact Study shall 

identify (1) any system constraints, identified with specificity by transmission 

element or flowgate, (2) redispatch options (when requested by an Eligible 
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Customer) including, to the extent possible, an estimate of the cost of 

redispatch, (3) available options for installation of automatic devices to curtail 

service (when requested by an Eligible Customer), and (4) additional Direct 

Assignment Facilities or Network Upgrades required to provide the requested 

service. For customers requesting the study of redispatch options, the System 

Impact Study shall (1) identify all resources located within the Transmission 

Provider’s Control Area that can significantly contribute toward relieving the 

system constraint and (2) provide a measurement of each resource’s impact on 

the system constraint. If the Transmission Provider possesses information 

indicating that any resource outside its Control Area could relieve the 

constraint, it shall identify each such resource in the System Impact Study. In 

the event that the Transmission Provider is unable to complete the required 

System Impact Study within such time period, it shall so notify the Eligible 

Customer and provide an estimated completion date along with an explanation 

of the reasons why additional time is required to complete the required 

studies. A copy of the completed System Impact Study and related work 

papers shall be made available to the Eligible Customer as soon as the System 

Impact Study is complete. The Transmission Provider will use the same due 

diligence in completing the System Impact Study for an Eligible Customer as 

it uses when completing studies for itself. The Transmission Provider shall 
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notify the Eligible Customer immediately upon completion of the System 

Impact Study if the Transmission System will be adequate to accommodate all 

or part of a request for service or that no costs are likely to be incurred for new 

transmission facilities or upgrades. In order for a request to remain a 

Completed Application, within fifteen (15) days of completion of the System 

Impact Study the Eligible Customer must execute a Service Agreement or 

request the filing of an unexecuted Service Agreement, or the Application 

shall be deemed terminated and withdrawn. 

32.4 Facilities Study Procedures: 

If a System Impact Study indicates that additions or upgrades to the 

Transmission System are needed to supply the Eligible Customer's service 

request, the Transmission Provider, within thirty (30) days of the completion 

of the System Impact Study, shall tender to the Eligible Customer a Facilities 

Study Agreement pursuant to which the Eligible Customer shall agree to 

reimburse the Transmission Provider for performing the required Facilities 

Study. For a service request to remain a Completed Application, the Eligible 

Customer shall execute the Facilities Study Agreement and return it to the 

Transmission Provider within fifteen (15) days. If the Eligible Customer 

elects not to execute the Facilities Study Agreement, its Application shall be 

deemed withdrawn and its deposit shall be returned with interest. Upon 
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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. 
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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 
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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. 
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33.4 Curtailments of Scheduled Deliveries: 

If a transmission constraint on the Transmission Provider's Transmission 

System cannot be relieved through the implementation of least-cost redispatch 

procedures and the Transmission Provider determines that it is necessary to 

Curtail scheduled deliveries, the Parties shall Curtail such schedules in 

accordance with the Network Operating Agreement or pursuant to the 

Transmission Loading Relief procedures specified in Attachment J. 

33.5 Allocation of Curtailments: 

The Transmission Provider shall, on a non-discriminatory basis, Curtail the 

transaction(s) that effectively relieve the constraint. However, to the extent 

practicable and consistent with Good Utility Practice, any Curtailment will be 

shared by the Transmission Provider and Network Customer in proportion to 

their respective Load Ratio Shares. The Transmission Provider shall not 

direct the Network Customer to Curtail schedules to an extent greater than the 

Transmission Provider would Curtail the Transmission Provider's schedules 

under similar circumstances. 

33.6 Load Shedding: 

To the extent that a system contingency exists on the Transmission Provider's 

Transmission System and the Transmission Provider determines that it is 

necessary for the Transmission Provider and the Network Customer to shed 
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load, the Parties shall shed load in accordance with previously established 

procedures under the Network Operating Agreement. 

33.7 System Reliability: 

Notwithstanding any other provisions of this Tariff, the Transmission Provider 

reserves the right, consistent with Good Utility Practice and on a not unduly 

discriminatory basis, to Curtail Network Integration Transmission Service 

without liability on the Transmission Provider's part for the purpose of making 

necessary adjustments to, changes in, or repairs on its lines, substations and 

facilities, and in cases where the continuance of Network Integration 

Transmission Service would endanger persons or property. In the event of 

any adverse condition(s) or disturbance(s) on the Transmission Provider's 

Transmission System or on any other system(s) directly or indirectly 

interconnected with the Transmission Provider's Transmission System, the 

Transmission Provider, consistent with Good Utility Practice, also may Curtail 

Network Integration Transmission Service in order to (i) limit the extent or 

damage of the adverse condition(s) or disturbance(s), (ii) prevent damage to 

generating or transmission facilities, or (iii) expedite restoration of service. 

The Transmission Provider will give the Network Customer as much advance 

notice as is practicable in the event of such Curtailment. Any Curtailment of 

Network Integration Transmission Service will be not unduly discriminatory 
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relative to the Transmission Provider's use of the Transmission System on 

behalf of its Native Load Customers. The Transmission Provider shall specify 

the rate treatment and all related terms and conditions applicable in the event 

that the Network Customer fails to respond to established Load Shedding and 

Curtailment procedures. 

34 Rates and Charges 

 The Network Customer shall pay the Transmission Provider for any Direct 

Assignment Facilities, Ancillary Services, and applicable study costs, consistent 

with Commission policy, along with the following: 

34.1 Monthly Demand Charge: 

The Network Customer shall pay a monthly Demand Charge, which shall be 

determined by multiplying its Load Ratio Share times one twelfth (1/12) of the 

Transmission Provider's Annual Transmission Revenue Requirement specified 

in Schedule H. 

34.2 Determination of Network Customer's Monthly Network Load: 

The Network Customer's monthly Network Load is its hourly load (including 

its designated Network Load not physically interconnected with the 

Transmission Provider under Section 31.3) coincident with the Transmission 

Provider's Monthly Transmission System Peak. 
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34.3 Determination of Transmission Provider's Monthly Transmission 

System Load: 

The Transmission Provider's monthly Transmission System load is the 

Transmission Provider's Monthly Transmission System Peak minus the 

coincident peak usage of all Firm Point-To-Point Transmission Service 

customers pursuant to Part II of this Tariff plus the Reserved Capacity of all 

Firm Point-To-Point Transmission Service customers. 

34.4 Redispatch Charge: 

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. 
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35 Operating Arrangements 

35.1 Operation under The Network Operating Agreement: 

The Network Customer shall plan, construct, operate and maintain its facilities 

in accordance with Good Utility Practice and in conformance with the 

Network Operating Agreement. 

35.2 Network Operating Agreement: 

The terms and conditions under which the Network Customer shall operate its 

facilities and the technical and operational matters associated with the 

implementation of Part III of the Tariff shall be specified in the Network 

Operating Agreement. The Network Operating Agreement shall provide for 

the Parties to (i) operate and maintain equipment necessary for integrating the 

Network Customer within the Transmission Provider's Transmission System 

(including, but not limited to, remote terminal units, metering, 

communications equipment and relaying equipment), (ii) transfer data 

between the Transmission Provider and the Network Customer (including, but 

not limited to, heat rates and operational characteristics of Network Resources, 

generation schedules for units outside the Transmission Provider's 

Transmission System, interchange schedules, unit outputs for redispatch 

required under Section 33, voltage schedules, loss factors and other real time 

data), (iii) use software programs required for data links and constraint 
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dispatching, (iv) exchange data on forecasted loads and resources necessary 

for long-term planning, and (v) address any other technical and operational 

considerations required for implementation of Part III of the Tariff, including 

scheduling protocols. The Network Operating Agreement will recognize that 

the Network Customer shall either (i) operate as a Control Area under 

applicable guidelines of the Electric Reliability Organization (ERO) as 

defined in 18 C.F.R. § 39.1, (ii) satisfy its Control Area requirements, 

including all necessary Ancillary Services, by contracting with the 

Transmission Provider, or (iii) satisfy its Control Area requirements, including 

all necessary Ancillary Services, by contracting with another entity, consistent 

with Good Utility Practice, which satisfies the applicable reliability guidelines 

of the ERO. The Transmission Provider shall not unreasonably refuse to 

accept contractual arrangements with another entity for Ancillary Services. 

The Network Operating Agreement is included in Attachment G. 

35.3 Network Operating Committee: 

A Network Operating Committee (Committee) shall be established to 

coordinate operating criteria for the Parties' respective responsibilities under 

the Network Operating Agreement. Each Network Customer shall be entitled 

to have at least one representative on the Committee. The Committee shall 
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meet from time to time as need requires, but no less than once each calendar 

year. 
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SCHEDULE 1 

Scheduling, System Control and Dispatch Service 

 This service is required to schedule the movement of power through, out of, 

within, or into a Control Area. This service can be provided only by the operator of the 

Control Area in which the transmission facilities used for transmission service are 

located. Scheduling, System Control and Dispatch Service is to be provided directly by 

the Transmission Provider (if the Transmission Provider is the Control Area operator) or 

indirectly by the Transmission Provider making arrangements with the Control Area 

operator that performs this service for the Transmission Provider's Transmission System. 

The Transmission Customer must purchase this service from the Transmission Provider 

or the Control Area operator. The charges for Scheduling, System Control and Dispatch 

Service are to be based on the rates set forth below. To the extent the Control Area 

operator performs this service for the Transmission Provider, charges to the Transmission 

Customer are to reflect only a pass-through of the costs charged to the Transmission 

Provider by that Control Area operator. 
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SCHEDULE 2 

Reactive Supply and Voltage Control from 

Generation or Other Sources Service 

 In order to maintain transmission voltages on the Transmission Provider's 

transmission facilities within acceptable limits, generation facilities and non-generation 

resources capable of providing this service that are under the control of the control area 

operator are operated to produce (or absorb) reactive power. Thus, Reactive Supply and 

Voltage Control from Generation or Other Sources Service must be provided for each 

transaction on the Transmission Provider's transmission facilities. The amount of 

Reactive Supply and Voltage Control from Generation or Other Sources Service that 

must be supplied with respect to the Transmission Customer's transaction will be 

determined based on the reactive power support necessary to maintain transmission 

voltages within limits that are generally accepted in the region and consistently adhered 

to by the Transmission Provider. 

 

 Reactive Supply and Voltage Control from Generation or Other Sources Service is 

to be provided directly by the Transmission Provider (if the Transmission Provider is the 

Control Area operator) or indirectly by the Transmission Provider making arrangements 

with the Control Area operator that performs this service for the Transmission Provider's 

Transmission System. The Transmission Customer must purchase this service from the 

Transmission Provider or the Control Area operator. The charges for such service will be 
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based on the rates set forth below. To the extent the Control Area operator performs this 

service for the Transmission Provider, charges to the Transmission Customer are to 

reflect only a pass-through of the costs charged to the Transmission Provider by the 

Control Area operator. 
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SCHEDULE 3 

Regulation and Frequency Response Service 

 Regulation and Frequency Response Service is necessary to provide for the 

continuous balancing of resources (generation and interchange) with load and for 

maintaining scheduled Interconnection frequency at sixty cycles per second (60 Hz). 

Regulation and Frequency Response Service is accomplished by committing on-line 

generation whose output is raised or lowered (predominantly through the use of 

automatic generating control equipment) and by other non-generation resources capable 

of providing this service as necessary to follow the moment-by-moment changes in load. 

The obligation to maintain this balance between resources and load lies with the 

Transmission Provider (or the Control Area operator that performs this function for the 

Transmission Provider). The Transmission Provider must offer this service when the 

transmission service is used to serve load within its Control Area. The Transmission 

Customer must either purchase this service from the Transmission Provider or make 

alternative comparable arrangements to satisfy its Regulation and Frequency Response 

Service obligation. The amount of and charges for Regulation and Frequency Response 

Service are set forth below. To the extent the Control Area operator performs this service 

for the Transmission Provider, charges to the Transmission Customer are to reflect only a 

pass-through of the costs charged to the Transmission Provider by that Control Area 

operator. 
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SCHEDULE 4 

Energy Imbalance Service 

 Energy Imbalance Service is provided when a difference occurs between the 

scheduled and the actual delivery of energy to a load located within a Control Area over a 

single hour. The Transmission Provider must offer this service when the transmission 

service is used to serve load within its Control Area. The Transmission Customer must 

either purchase this service from the Transmission Provider or make alternative 

comparable arrangements, which may include use of non-generation resources capable of 

providing this service, to satisfy its Energy Imbalance Service obligation. To the extent 

the Control Area operator performs this service for the Transmission Provider, charges to 

the Transmission Customer are to reflect only a pass-through of the costs charged to the 

Transmission Provider by that Control Area operator. The Transmission Provider may 

charge a Transmission Customer a penalty for either hourly energy imbalances under this 

Schedule or a penalty for hourly generator imbalances under Schedule 9 for imbalances 

occurring during the same hour, but not both unless the imbalances aggravate rather than 

offset each other. 

 The Transmission Provider shall establish charges for energy imbalance based on 

the deviation bands as follows: (i) deviations within +/- 1.5 percent (with a minimum of 

2 MW) of the scheduled transaction to be applied hourly to any energy imbalance that 

occurs as a result of the Transmission Customer's scheduled transaction(s) will be netted 
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on a monthly basis and settled financially, at the end of the month, at 100 percent of 

incremental or decremental cost; (ii) deviations greater than +/- 1.5 percent up to 7.5 

percent (or greater than 2 MW up to 10 MW) of the scheduled transaction to be applied 

hourly to any energy imbalance that occurs as a result of the Transmission Customer’s 

scheduled transaction(s) will be settled financially, at the end of each month, at 110 

percent of incremental cost or 90 percent of decremental cost, and (iii) deviations greater 

than +/- 7.5 percent (or 10 MW) of the scheduled transaction to be applied hourly to any 

energy imbalance that occurs as a result of the Transmission Customer’s scheduled 

transaction(s) will be settled financially, at the end of each month, at 125 percent of 

incremental cost or 75 percent of decremental cost. 

For purposes of this Schedule, incremental cost and decremental cost represent the 

Transmission Provider’s actual average hourly cost of the last 10 MW dispatched for any 

purpose, i.e., to supply the Transmission Provider’s Native Load Customers, correct 

imbalances, or make off-system sales, based on the replacement cost of fuel, unit heat 

rates, start-up costs (including any commitment and redispatch costs), incremental 

operation and maintenance costs, and purchased and interchange power costs and taxes, 

as applicable. 
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SCHEDULE 5 

Operating Reserve - Spinning Reserve Service 

 Spinning Reserve Service is needed to serve load immediately in the event of a 

system contingency. Spinning Reserve Service may be provided by generating units that 

are on-line and loaded at less than maximum output and by non-generation resources 

capable of providing this service. The Transmission Provider must offer this service 

when the transmission service is used to serve load within its Control Area. The 

Transmission Customer must either purchase this service from the Transmission Provider 

or make alternative comparable arrangements to satisfy its Spinning Reserve Service 

obligation. The amount of and charges for Spinning Reserve Service are set forth below. 

To the extent the Control Area operator performs this service for the Transmission 

Provider, charges to the Transmission Customer are to reflect only a pass-through of the 

costs charged to the Transmission Provider by that Control Area operator. 
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SCHEDULE 6 

Operating Reserve - Supplemental Reserve Service 

 Supplemental Reserve Service is needed to serve load in the event of a system 

contingency; however, it is not available immediately to serve load but rather within a 

short period of time. Supplemental Reserve Service may be provided by generating units 

that are on-line but unloaded, by quick-start generation or by interruptible load or other 

non-generation resources capable of providing this service. The Transmission Provider 

must offer this service when the transmission service is used to serve load within its 

Control Area. The Transmission Customer must either purchase this service from the 

Transmission Provider or make alternative comparable arrangements to satisfy its 

Supplemental Reserve Service obligation. The amount of and charges for Supplemental 

Reserve Service are set forth below. To the extent the Control Area operator performs 

this service for the Transmission Provider, charges to the Transmission Customer are to 

reflect only a pass-through of the costs charged to the Transmission Provider by that 

Control Area operator. 
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SCHEDULE 7 

Long-Term Firm and Short-Term Firm Point-To-Point 

Transmission Service 

 The Transmission Customer shall compensate the Transmission Provider each 

month for Reserved Capacity at the sum of the applicable charges set forth below: 

1) Yearly delivery: one-twelfth of the demand charge of $ /KW of Reserved 

Capacity per year. 

2) Monthly delivery: $ /KW of Reserved Capacity per month. 

3) Weekly delivery: $ /KW of Reserved Capacity per week. 

4) Daily delivery: $ /KW of Reserved Capacity per day. 

The total demand charge in any week, pursuant to a reservation for Daily delivery, 

shall not exceed the rate specified in section (3) above times the highest amount in 

kilowatts of Reserved Capacity in any day during such week. 

5) Discounts: Three principal requirements apply to discounts for transmission 

service as follows (1) any offer of a discount made by the Transmission Provider 

must be announced to all Eligible Customers solely by posting on the OASIS, (2) 

any customer-initiated requests for discounts (including requests for use by one's 

wholesale merchant or an Affiliate's use) must occur solely by posting on the 

OASIS, and (3) once a discount is negotiated, details must be immediately posted 

on the OASIS. For any discount agreed upon for service on a path, from point(s) 

of receipt to point(s) of delivery, the Transmission Provider must offer the same 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 141 

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. 

6) Resales: The rates and rules governing charges and discounts stated above shall 

not apply to resales of transmission service, compensation for which shall be 

governed by section 23.1 of the Tariff. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 142 

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. 143 

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. 

6) Resales: The rates and rules governing charges and discounts stated above shall 

not apply to resales of transmission service, compensation for which shall be 

governed by section 23.1 of the Tariff. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 144 

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, to the extent it is physically feasible to do so from its resources or 

from resources available to it, when Transmission Service is used to deliver energy from 

a generator located within its Control Area. The Transmission Customer must either 

purchase this service from the Transmission Provider or make alternative comparable 

arrangements, which may include use of non-generation resources capable of providing 

this service, to satisfy its Generator Imbalance Service obligation. To the extent the 

Control Area operator performs this service for the Transmission Provider, charges to the 

Transmission Customer are to reflect only a pass-through of the costs charged to the 

Transmission Provider by that Control Area Operator. The Transmission Provider may 

charge a Transmission Customer a penalty for either hourly generator imbalances under 

this Schedule or a penalty for hourly energy imbalances under Schedule 4 for imbalances 

occurring during the same hour, but not both unless the imbalances aggravate rather than 

offset each other. 

 The Transmission Provider shall establish charges for generator imbalance based 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 145 

on the deviation bands as follows: (i) deviations within +/- 1.5 percent (with a minimum 

of 2 MW) of the scheduled transaction to be applied hourly to any generator imbalance 

that occurs as a result of the Transmission Customer's scheduled transaction(s) will be 

netted on a monthly basis and settled financially, at the end of each month, at 100 percent 

of incremental or decremental cost, (ii) deviations greater than +/- 1.5 percent up to 7.5 

percent (or greater than 2 MW up to 10 MW) of the scheduled transaction to be applied 

hourly to any generator imbalance that occurs as a result of the Transmission Customer's 

scheduled transaction(s) will be settled financially, at the end of each month, at 110 

percent of incremental cost or 90 percent of decremental cost, and (iii) deviations greater 

than +/- 7.5 percent (or 10 MW) of the scheduled transaction to be applied hourly to any 

generator imbalance that occurs as a result of the Transmission Customer's scheduled 

transaction(s) will be settled at 125 percent of incremental cost or 75 percent of 

decremental cost, except that an intermittent resource will be exempt from this deviation 

band and will pay the deviation band charges for all deviations greater than the larger of 

1.5 percent or 2 MW. An intermittent resource, for the limited purpose of this Schedule 

is an electric generator that is not dispatchable and cannot store its fuel source and 

therefore cannot respond to changes in system demand or respond to transmission 

security constraints. 

1. Notwithstanding the foregoing, deviations from scheduled transactions in 

order to respond to directives by the Transmission Provider, a balancing authority, or a 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 146 

reliability coordinator shall not be subject to the deviation bands identified above and, 

instead, shall be settled financially, at the end of the month, at 100 percent of incremental 

and decremental cost. Such directives may include instructions to correct frequency 

decay, respond to a reserve sharing event, or change output to relieve congestion. 

2. For purposes of this Schedule, incremental cost and decremental cost 

represent the Transmission Provider’s actual average hourly cost of the last 10 MW 

dispatched for any purpose, i.e., to supply the Transmission Provider’s Native Load 

Customers, correct imbalances, or make off-system sales, based on the replacement cost 

of fuel, unit heat rates, start-up costs (including any commitment and redispatch costs), 

incremental operation and maintenance costs, and purchased and interchange power costs 

and taxes, as applicable. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 147 

 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. 148 

 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. 149 

 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. 150 

 Page 4 of 4 

8.0 Service under this Agreement may be subject to some combination of the charges 

detailed below. (The appropriate charges for individual transactions will be 

determined in accordance with the terms and conditions of the Tariff.) 

8.1 Transmission Charge:________________________________ 

 __________________________________________________ 

8.2 System Impact and/or Facilities Study Charge(s): 

 __________________________________________________ 

 __________________________________________________ 

8.3 Direct Assignment Facilities Charge:____________________ 

 __________________________________________________ 

8.4 Ancillary Services Charges: ______________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 151 

 Page 1 of 4 

ATTACHMENT A-1 

Form Of Service Agreement For 

The Resale, Reassignment Or Transfer Of 

Point-To-Point Transmission Service 

1.0 This Service Agreement, dated as of _______________, is entered into, by and 

between ____________ (the Transmission Provider), and ____________ (the 

Assignee). 

2.0 The Assignee has been determined by the Transmission Provider to be an Eligible 

Customer under the Tariff pursuant to which the transmission service rights to be 

transferred were originally obtained. 

3.0 The terms and conditions for the transaction entered into under this Service 

Agreement shall be subject to the terms and conditions of Part II of the 

Transmission Provider’s Tariff, except for those terms and conditions negotiated 

by the Reseller of the reassigned transmission capacity (pursuant to Section 23.1 

of this Tariff) and the Assignee, to include: contract effective and termination 

dates, the amount of reassigned capacity or energy, point(s) of receipt and 

delivery. Changes by the Assignee to the Reseller’s Points of Receipt and Points 

of Delivery will be subject to the provisions of Section 23.2 of this Tariff. 

4.0 The Transmission Provider shall credit the Reseller for the price reflected in the 

Assignee’s Service Agreement or the associated OASIS schedule. 

5.0 Any notice or request made to or by either Party regarding this Service Agreement 

shall be made to the representative of the other Party as indicated below. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 152 

 ` Page 2 of 4 

Transmission Provider: 

______________________________ 

______________________________ 

______________________________ 

Assignee: 

______________________________ 

______________________________ 

______________________________ 

6.0 The Tariff is incorporated herein and made a part hereof. 

IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be 

executed by their respective authorized officials. 

Transmission Provider: 

By:____________________________ ______________________ _______________ 

 Name Title Date 

Assignee: 

By:____________________________ ______________________ _______________ 

 Name Title Date 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 153 

 Page 3 of 4 

Specifications For The Resale, Reassignment Or Transfer of 

Long-Term Firm Point-To-Point Transmission Service

1.0 Term of Transaction: ___________________________________ 

 Start Date: ___________________________________________ 

 Termination Date: _____________________________________ 

2.0 Description of capacity and energy to be transmitted by Transmission Provider 

including the electric Control Area in which the transaction originates. 

 _______________________________________________________ 

3.0 Point(s) of Receipt:___________________________________ 

 Delivering Party:_______________________________________ 

4.0 Point(s) of Delivery:__________________________________ 

 Receiving Party:______________________________________ 

5.0 Maximum amount of reassigned capacity: __________________ 

6.0 Designation of party(ies) subject to reciprocal service 

obligation:_________________________________________________________

__________________________________________________________________

__________________________________________________________________

__________________________________________________________________ 

7.0 Name(s) of any Intervening Systems providing transmission 

service:____________________________________________________________

__________________________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 154 

 Page 4 of 4 

8.0 Service under this Agreement may be subject to some combination of the charges 

detailed below. (The appropriate charges for individual transactions will be 

determined in accordance with the terms and conditions of the Tariff.) 

8.1 Transmission Charge:________________________________ 

 __________________________________________________ 

8.2 System Impact and/or Facilities Study Charge(s): 

 __________________________________________________ 

 __________________________________________________ 

8.3 Direct Assignment Facilities Charge:____________________ 

 __________________________________________________ 

8.4 Ancillary Services Charges: ______________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

 __________________________________________________ 

9.0 Name of Reseller of the reassigned transmission capacity: 

___________________________________________________________ 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 155 

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. 156 

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. 157 

ATTACHMENT C 

Methodology To Assess Available Transfer Capability 

The Transmission Provider must include, at a minimum, the following information 

concerning its ATC calculation methodology: 

(1) A detailed description of the specific mathematical algorithm used to calculate 

firm and non-firm ATC (and AFC, if applicable) for its scheduling horizon (same day 

and real-time), operating horizon (day ahead and pre-schedule) and planning horizon 

(beyond the operating horizon); 

(2) A process flow diagram that illustrates the various steps through which ATC/AFC 

is calculated; and 

(3) A detailed explanation of how each of the ATC components is calculated for both 

the operating and planning horizons. 

(a) For TTC, a Transmission Provider shall: (i) explain its definition of TTC; (ii) 

explain its TTC calculation methodology; (iii) list the databases used in its TTC 

assessments; and (iv) explain the assumptions used in its TTC assessments regarding load 

levels, generation dispatch, and modeling of planned and contingency outages. 

(b) For ETC, a transmission provider shall explain: (i) its definition of ETC; (ii) the 

calculation methodology used to determine the transmission capacity to be set aside for 

native load (including network load), and non-OATT customers (including, if applicable, 

an explanation of assumptions on the selection of generators that are modeled in service); 

(iii) how point-to-point transmission service requests are incorporated; (iv) how rollover 

rights are accounted for; (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); and (vi) describe the step-by-step modeling study 

methodology and criteria for adding or eliminating flowgates (permanent and temporary). 

(c) If a Transmission Provider uses an AFC methodology to calculate ATC, it shall: 

(i) explain its definition of AFC; (ii) explain its AFC calculation methodology; (iii) 

explain its process for converting AFC into ATC for OASIS posting; (iv) list the 

databases used in its AFC assessments; and (v) explain the assumptions used in its AFC 

assessments regarding load levels, generation dispatch, and modeling of planned and 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 158 

contingency outages. 

(d) For TRM, a Transmission Provider shall explain: (i) its definition of TRM; (ii) its 

TRM calculation methodology (e.g., its assumptions on load forecast errors, forecast 

errors in system topology or distribution factors and loop flow sources); (iii) the 

databases used in its TRM assessments; (iv) the conditions under which the transmission 

provider uses TRM. A Transmission Provider that does not set aside transfer capability 

for TRM must so state. 

(e) For CBM, the Transmission Provider shall state include a specific and selfcontained narrative explanation of its CBM practice, including: (i) an identification of the 

entity who performs the resource adequacy analysis for CBM determination; (ii) the 

methodology used to perform generation reliability assessments (e.g., probabilistic or 

deterministic); (iii) an explanation of whether the assessment method reflects a specific 

regional practice; (iv) the assumptions used in this assessment; and (v) the basis for the 

selection of paths on which CBM is set aside. 

(f) In addition, for CBM, a Transmission Provider shall: (i) explain its definition of 

CBM; (ii) list the databases used in its CBM calculations; and (iii) demonstrate that there 

is no double-counting of contingency outages when performing CBM, TTC, and TRM 

calculations. 

(g) The Transmission Provider shall explain its procedures for allowing the use of 

CBM during emergencies (with an explanation of what constitutes an emergency, the 

entities that are permitted to use CBM during emergencies and the procedures which 

must be followed by the transmission providers’ merchant function and other loadserving entities when they need to access CBM). If the Transmission Provider’s practice 

is not to set aside transfer capability for CBM, it shall so state. 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 159 

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. 160 

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. 161 

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. 162 

ATTACHMENT G 

Network Operating Agreement 

 To be filed by the Transmission Provider 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 163 

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. 164 

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. 165 

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. 166 

ATTACHMENT K 

Transmission Planning Process 

The Transmission Provider shall establish a coordinated, open and transparent planning 

process with its Network and Firm Point-to-Point Transmission Customers and other 

interested parties, including the coordination of such planning with interconnected 

systems within its region, to ensure that the Transmission System is planned to meet the 

needs of both the Transmission Provider and its Network and Firm Point-to-Point 

Transmission Customers on a comparable and nondiscriminatory basis. The 

Transmission Provider’s coordinated, open and transparent planning process shall be 

provided as an attachment to the Transmission Provider’s Tariff. 

The Transmission Provider’s planning process shall satisfy the following nine principles, 

as defined in the Final Rule in Docket No. RM05-25-000: coordination, openness, 

transparency, information exchange, comparability, dispute resolution, regional 

participation, economic planning studies, and cost allocation for new projects. The 

planning process shall also provide a mechanism for the recovery and allocation of 

planning costs consistent with the Final Rule in Docket No. RM05-25-000. 

The Transmission Provider’s planning process must include sufficient detail to enable 

Transmission Customers to understand: 

(i) The process for consulting with customers and neighboring transmission providers; 

(ii) The notice procedures and anticipated frequency of meetings; 

(iii) The methodology, criteria, and processes used to develop transmission plans; 

(iv) The method of disclosure of criteria, assumptions and data underlying transmission 

system plans; 

(v) The obligations of and methods for customers to submit data to the transmission 

provider; 

(vi) The dispute resolution process; 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 167 

(vii) The transmission provider’s study procedures for economic upgrades to address 

congestion or the integration of new resources; and 

(viii) The relevant cost allocation procedures or principles. 

 
(Name of Transmission Provider) Open Access Transmission Tariff 

Original Sheet No. 168 

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.