Preventing Undue Discrimination and Preference in Transmission Service

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 37

[Docket Nos. RM05-17-003 and RM05-25-003; Order No. 890-B]

Preventing Undue Discrimination and Preference in Transmission Service

Issued June 23, 2008.

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Order on rehearing and clarification.

SUMMARY:

The Federal Energy Regulatory Commission affirms its basic determinations in Order Nos. 890 and 890-A, 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: Strengthen the

pro forma

OATT to ensure that it achieves its original purpose of remedying undue discrimination; provide greater specificity to reduce opportunities for undue discrimination and facilitate the Commission's enforcement; and increase transparency in the rules applicable to planning and use of the transmission system.

DATES:

Effective Date:

This rule will become effective September 8, 2008.

FOR FURTHER INFORMATION CONTACT:

W. Mason Emnett (Legal Information), Office of the General Counsel—Energy Markets, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6540.

Daniel Hedberg (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6243.

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph

Number

I. Introduction

1

II. Reforms of the OATT

7

A. Consistency and Transparency of ATC Calculations

7

1. Consistency

8

2. Transparency

25

B. Transmission Pricing

38

1. Energy and Generation Imbalances

38

2. Credits for Network Customers

46

3. Capacity Reassignment

68

4. Operational Penalties

87

5. “Higher Of” Pricing Policy

102

6. Other Ancillary Services

109

C. Non-Rate Terms and Conditions

116

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

116

2. Rollover Rights

141

3. Acquisition of Transmission Service

155

4. Designation of Network Resources

162

5. Clarifications Related to Network Service

216

6. OATT Definitions

220

III. Information Collection Statement

250

IV. Document Availability

251

V. Effective Date and Congressional Notification

254

Appendix A: Petitioners' Acronyms

Appendix B:

Pro Forma

Open Access Transmission Tariff

Before Commissioners:

Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

Order on Rehearing and Clarification

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 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.

1

Preventing Undue Discrimination and Preference in Transmission Service,

Order No. 890, 72 FR 12266 (March 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007) (Order No. 890),

order on reh'g,

Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 (2007) (Order No. 890-A).

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 (D.C. Cir. 2000) (

TAPS

v.

FERC

),

aff'd sub nom. New York

v.

FERC,

535 U.S. 1 (2002).

2. In Order No. 890-A, the Commission largely affirmed the reforms adopted in Order No. 890. The Commission noted that work was well underway to develop consistent practices governing the calculation of ATC in coordination with the North American Electric Reliability Corporation (NERC) and the North American Energy Standards Board (NAESB). When complete, the reliability standards developed through NERC and the business practices developed

through NAESB will eliminate the broad discretion that transmission providers have in calculating ATC, increasing nondiscriminatory access to the grid and ensuring that customers are treated fairly in seeking alternative power supplies.

3. The Commission also noted the substantial resources that transmission providers have dedicated to the development of transmission planning processes in response to Order No. 890. 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.

4. 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 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 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.

5. The Commission concluded that, taken together, these and other reforms adopted in Order No. 890 will better enable the

pro forma

OATT to achieve the core objective of remedying undue discrimination in the provision of transmission service. The Commission therefore rejected requests to eliminate, or substantially modify, the various reforms adopted in Order No. 890. The Commission did, however, grant rehearing and clarification regarding certain revisions to its regulations and the

pro forma

OATT.

Several petitioners have sought further rehearing and clarification of the Commission's determinations in Order No. 890-A.

3

3

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

6. The Commission largely affirms the determinations reached in Order No. 890-A, granting limited rehearing and clarification to address certain specific matters raised by petitioners. Revisions to the

pro forma

OATT are required to implement several of these determinations, although none disturb the fundamental nature of the reforms adopted in Order No. 890. We therefore 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 a Federal Power Act (FPA) section 206 filing that contains the revised non-rate terms and conditions of the

pro forma

OATT stated in Appendix B within 60 days of publication of this order in the

Federal Register.

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 in Appendix B within 90 days of publication of this order in the

Federal Register.

II. Reforms of the OATT

A. Consistency and Transparency of ATC Calculations

7. In Order No. 890-A, the Commission affirmed its conclusion in Order No. 890 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 ATC-related reforms adopted by the Commission. A number of petitioners seek rehearing and/or clarification regarding the Commission's ATC-related determinations in Order No. 890-A, which we address below.

1. Consistency

a. Necessary Degree of and Process To Achieve Consistency

8. The Commission affirmed the decision in Order No. 890 to require consistency of all ATC components

4

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. In response to petitioner requests, the Commission clarified that adjacent transmission providers must coordinate and exchange data and assumptions to achieve consistent ATC values on either side of a single interface, regardless of whether they use the same or different ATC methodologies. The Commission also reiterated that its regulations require the posting of ATC values associated with a particular path, not available flowgate capacity (AFC) values associated with a flowgate. The Commission clarified, however, that a transmission provider is free to post both ATC and AFC values. The Commission further clarified that transmission-owning utilities in an RTO 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.

4

The ATC components are total transfer capability (TTC), existing transmission commitments (ETC), capacity benefit margin (CBM), and transmission reserve margin (TRM).

Requests for Rehearing and Clarification

9. Duke, EEI, and E.ON U.S. object to the requirement that ATC values be consistent on either side of an interface and suggest alternatively that transmission providers be required to achieve consistent TTC values on either side of the interface. Duke contends that achieving consistency in TTC values will not necessarily result in consistent ATC values. EEI agrees, arguing that ATC will be identical on both sides of an interface only in the unlikely event that the transmission providers each simultaneously receive and process corresponding transmission requests and schedules for the same type of product. EEI contends that transmission providers therefore will have to expend substantial effort and resources to constantly monitor and investigate differences in ATC values, the burden of which EEI argues outweighs any benefit realized.

10. Joined by E.ON U.S., Southern suggests that the Commission clarify that “consistent ATC values” does not mean that ATC or TTC values on either side of an interface must be identical. Southern argues that interpreting “consistent” to mean “identical” would be contrary to reliable planning and not reasonably achievable. Southern contends that there are a number of reasons why adjacent transmission

providers may have varying ATC and TTC values on an interface, including partial path transmission service, CBM and TRM, and the impacts of multiple interfaces.

11. EEI and E.ON U.S. also request the Commission clarify that the process of achieving consistency of TTC values should occur through the ongoing NERC and NAESB processes. They argue that the Commission in Order No. 890 only required the consistency of components, definitions, data and assumptions with respect to ATC and its components, including TTC. They contend that the Commission did not require consistency in ATC values or provide for a means to reconcile differences in ATC calculations performed by multiple transmission providers. EEI and E.ON U.S. suggest that it may take additional time for NERC and NAESB to develop standards and business practices to achieve consistency in TTC values or reconcile differences between ATC values at common interfaces. Duke requests confirmation that compliance with the NERC and NAESB methodologies regarding TTC and related calculations, once they have been adopted and implemented, is sufficient to comply with the consistency requirement imposed in Order No. 890-A.

12. Entergy requests the Commission to clarify that Order No. 890-A was not intended to reverse the Commission's prior determination that Entergy and other transmission providers can rely on the scenario analyzer to satisfy the ATC posting requirements in part 37 of the Commission's regulations.

5

Although Entergy uses an AFC methodology, it posts ATC values on a path-specific basis by providing transmission customers a scenario analyzer tool that allows them to instantaneously evaluate transfer capability on a source-to-sink basis. Entergy states that its scenario analyzer is also relied on by other transmission providers, such as the Southwest Power Pool, Inc. and the Midwest Independent Transmission System Operator, Inc. Entergy states that the scenario analyzer will notify the customer the proposed request could be approved if sufficient AFC exists.

5

Citing Entergy Servs., Inc.,

106 FERC ¶ 61,115 (2004); 18 CFR 37.6(b)(2)(i) (2007).

13. Entergy notes that the Commission has previously concluded that “Entergy's AFC methodology meets the established minimum posting requirements for transmission capability set forth in Order No. 889,”

6

which Entergy argues were not changed in Order Nos. 890 or 890-A. If the Commission intended in Order No. 890-A to modify the requirements for posting ATC, or reverse its determination that the scenario analyzer complies with the posting requirements, Entergy requests clarification regarding what specific actions are required of transmission providers that rely on the AFC process. Entergy also asks that those transmission providers be allowed to continue using the scenario analyzer until those measures are in place. Entergy states that the sole purpose of the scenario analyzer has been to comply with the Commission's posting requirements and that transmission providers should not be required to maintain two different and duplicative systems for meeting those requirements.

6

See Entergy Servs., Inc.,

106 FERC ¶ 61,115 at P 50.

14. E.ON U.S. requests clarification that all transmission-owning utilities within an RTO 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, and not just transmission-owning utilities that are members of the RTO. E.ON U.S. states that many of its neighboring systems utilize AFC instead of ATC, requiring it to calculate AFC in order to transact with the adjacent RTO members, to alleviate seams issues with these neighboring systems, and increase transparency for across the border transactions. E.ON U.S. contends that AFC calculations are much more accurate means to determine if capacity is available on a flowgate than are ATC calculations. If the Commission declines to grant the requested clarification, E.ON U.S. seeks rehearing on the grounds that the Commission is creating new seams where they do not currently exist by requiring transmission capacity to be calculated differently on both sides of the border for such transactions.

Commission Determination

15. The Commission affirms the clarification provided in Order No. 890-A that adjacent transmission providers must coordinate and exchange data and assumptions to achieve consistent ATC values on either side of a single interface.

7

We disagree with petitioners arguing that “consistent” ATC values should not be interpreted as identical. We recognize that factors such as timing of reservation requests, acceptances, and confirmations, and multiple interfaces between and among transmission providers, can make it difficult to achieve coincidental, identical postings of ATC values on both sides of an interface. However, as the Commission explained in Order No. 890, if all of the ATC components and certain data inputs and assumptions are consistent, the ATC calculation methodologies being finalized by NERC through the reliability standards development process should produce predictable and sufficiently accurate, consistent, equivalent, and replicable results.

8

We therefore disagree that the directive to coordinate and exchange data and assumptions to achieve consistent ATC values on either side of an interface was newly imposed in Order No. 890-A. The Commission simply clarified that the requirement stated in Order No. 890 applies equally to calculations of ATC on either side of an interface.

7

See

Order No. 890-A at P 52.

8

See

Order No. 890 at P 210.

16. Public utilities have already been directed to work through the NERC and NAESB processes to achieve such consistency in ATC and TTC values. In response to Duke, the Commission will address whether the resulting reliability standards and business practices adequately satisfy this consistency requirement on review of those reliability standards and business practices. We note that public utilities were recently granted an extension of time to finalize their work through the NERC and NAESB processes. In Order No. 890, the Commission directed each transmission provider to file a revised Attachment C to its OATT to incorporate any changes associated with the revised reliability standards and business practices within 60 days of completion of the NERC and NAESB processes. We clarify that these revised Attachment C filings are due 60 days after the date on which the relevant reliability standards or business practices takes effect, not their submission for Commission review.

17. We grant the clarification requested by Entergy regarding the Commission's February 11, 2004 determination that Entergy's AFC methodology meets the minimum posting requirements for transmission capability set forth in Order No. 889.

9

The Commission did not amend in Order Nos. 890 or 890-A the obligation for transmission providers to post ATC values associated with a particular path instead of AFC values associated with a flowgate.

10

Prior determinations by the Commission that a particular practice satisfies that obligation, or waiving that

obligation altogether, therefore remain intact.

11

9

See Entergy Servs., Inc.,

106 FERC ¶ 61,115 at P 50.

10

See

18 CFR 37.6(b)(1)(i);

see also

Order No. 890 at P 211; Order No. 890-A at P 51.

11

See

Order No. 890-A at P 36.

18. We disagree with E.ON U.S. that non-member transmission-owning utilities within an RTO region are similarly situated to member transmission-owning utilities, which the Commission noted in Order No. 890-A may 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. RTO members that have retained control over certain transmission facilities operate those transmission facilities in coordination with the RTO. In comparison, non-RTO members provide transmission service independently and, therefore, for purposes of ATC calculation are similar to a transmission provider outside the RTO region. Nevertheless, we reiterate that a transmission provider is free to post both ATC and AFC values if it believes such postings provide additional transparency.

12

b. ATC Components—CBM and TRM

19. In Order No. 890-A, the Commission affirmed the decision in Order No. 890 to require 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. The Commission also affirmed the requirement that transmission providers design their transmission charges so that the class of customers not benefiting from the CBM set-aside,

i.e.

, point-to-point customers, does not pay a transmission charge that includes the cost of the CBM set-aside. The Commission explained that 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. The Commission also rejected requests to use CBM for reserve-sharing arrangements, reiterating that TRM is the appropriate category for reserve-sharing.

Requests for Rehearing and Clarification

20. Southern requests rehearing of the Commission's statement that non-firm point-to-point transmission customers only receive an indirect benefit from CBM. Southern contends that under normal conditions without generation deficiencies, non-firm point-to-point customers may use CBM set-aside capacity. Southern states that it has not called upon CBM to meet a generation deficit emergency in six years, resulting in that capacity consistently being made available to non-firm customers. Southern argues that non-firm customers therefore directly benefit from CBM and should bear transmission charges that include the cost of the capacity they are actually utilizing. If the Commission does not wish to make a generic determination, Southern asks the Commission to clarify that the issue of whether non-firm customers benefit from CBM will be addressed on a case-by-case basis.

21. TDU Systems request clarification of the Commission's statement in Order No. 890-A that TRM is the appropriate category for reserve sharing arrangements. TDU Systems request confirmation that, if a transmission provider is using another form of set-aside for reserve sharing purposes, such as CBM, the transmission providers' customers are entitled to comparable use of the form of set-aside. TDU Systems argue that comparability cannot be achieved where the transmission provider does not offer use of transmission capacity set-asides to LSE customers comparable to the use that the transmission provider allows itself.

12

See

Order No. 890-A at P 51.

Commission Determination

22. The Commission affirms the requirement adopted in Order No. 890, and affirmed in Order No. 890-A, that transmission providers design their transmission charges so that the class of customers not benefiting from the CBM set-aside,

i.e.

, point-to-point customers, does not pay a transmission charge that includes the cost of the CBM set-aside.

13

We disagree with Southern that non-firm customers benefit directly from the CBM set-aside. The Commission acknowledged in Order No. 890-A that capacity set aside for CBM may be made available to non-firm customers when not otherwise in use.

14

That benefit, however, is indirect and inferior to the direct benefits enjoyed by those entities that have the exclusive right to request the set-aside in the first instance.

13

See

Order No. 890 at P 263; Order No. 890-A at P 86.

14

See

Order No. 890-A at P 87.

23. The Commission acknowledged in Order No. 890-A that use of capacity set aside for CBM by non-firm customers may result in revenues that are credited to the transmission provider's cost of service, to the benefit of point-to-point customers.

15

The Commission stated its expectation that transmission providers would address in rate design filings any possibility for particular customers to receive an inappropriate credit for non-firm use of capacity set aside for CBM. Further clarification is unnecessary.

15

Id.

24. With regard to reserve sharing arrangements, the Commission clearly stated in Order No. 890-A that TRM is the appropriate category for reserve sharing arrangements and that, in comparison, CBM is used to meet generation reliability criteria in times of emergency generation deficiencies.

16

Therefore, transmission providers must use TRM, not CBM, for reserve sharing arrangements and make ATC set aside for that purpose available to all LSEs on a comparable basis for any reserve sharing arrangements they may have.

16

Id.

P 85.

2. Transparency

25. In Order No. 890-A, the Commission clarified 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. The Commission also clarified that underlying load forecast assumptions to be posted on OASIS should include economic and weather-related assumptions. The Commission concluded that posting load forecast and actual load data on a control area and LSE level does not raise serious competitive implications. The Commission stated that it would consider requests for exemption from this posting requirement on a case-by-case basis if there is customer-specific information deemed confidential by the affected customer that impedes the ability of the transmission provider to post this data.

17

17

Id.

P 143.

26. The Commission further clarified that transmission providers must make available, upon request and subject to appropriate confidentiality protections and CEII requirements, certain modeling data including load flow base cases and generation dispatch methodology and, subject to additional reasonable and applicable generator confidentiality limitations, production cost models (including assumptions, settings, study results, input data, etc.). The Commission declined to require transmission providers to post this information on OASIS.

Requests for Rehearing and Clarification

27. Duke seeks clarification of the requirement to post information requested by an affiliate when that information is already available to the

public. Duke suggests that only a notice that an affiliate requested a publicly-available study needs to be posted, and not the actual study, because the additional effort of posting the actual study would be redundant, burdensome, and without purpose.

28. Duke, EEI and Southern request rehearing to eliminate the requirement to post the underlying assumptions used to develop load forecasts on a daily basis, including economic and weather-related assumptions. They claim that the requirement is a substantial modification of regulations adopted in Order No. 890, is unduly burdensome, and may cause transmission providers to violate their contractual obligations by releasing proprietary assumptions and forecasts obtained from forecasting service providers. Southern also complains that it is unclear what is meant by “economic assumptions” and any requirement to provide daily updates of such assumptions would be unduly burdensome given the amount of effort required and negligible benefit that customers might gain from the information.

29. Duke argues that the Commission's expansion of posting requirements to include load forecast assumptions daily is an entirely new requirement for which notice and comment has not been provided. Duke contends that Constellation's request for rehearing of Order No. 890 mentioning load forecast assumptions was inadequate to provide notice because Constellation did not request that load forecast assumptions be posted on a daily basis or that load forecast assumptions unrelated to ATC calculations be posted.

30. If the Commission declines to eliminate this posting requirement, Duke suggests that it be amended to require a one-time (

i.e.

, not daily) posting of a list of factors that go into the peak load forecast, such as day of the week, a day's status as holiday or non-holiday, temperature, dew point, precipitation forecast,

etc.

If the Commission continues to require the daily posting of information, Duke seeks clarification regarding the granularity of such information given that it could vary widely over a control area. Duke questions whether, for example, PJM would have to post weather forecasts for each of its subregions. Until the Commission grants the requested clarification, Duke argues that the posting requirement should be waived or transmission providers should be permitted to satisfy the requirement by reference to commercial/government weather websites.

31. Southern seeks clarification of the requirement to make available, on request, the modeling data identified in paragraph 148 of Order No. 890-A. Southern states that it does not use all of the specified modeling data to calculate ATC, TTC, CBM and/or TRM. In particular, Southern argues that neither production cost models nor special protection systems and operation guides are used in its ATC calculations and that production cost models in particular are not even maintained by its transmission function given its highly sensitive nature. Southern asks the Commission to clarify that transmission providers are required to provide only the specified modeling data actually used in performing those calculations and that a transmission provider is not required to manufacture and/or produce the data in the event it does not use a particular input in its ATC calculations.

32. Duke also argues that production cost models and generation dispatch methodologies typically contain commercially sensitive or proprietary information or information that should not be released to the public. Duke acknowledges that the Commission stated that availability of production cost models would be subject to reasonable and applicable generator confidentiality limitations,

18

but argues that still would allow employees or consultants of competing entities to be provided access to sensitive data. Duke therefore asks the Commission to confirm that reasonable and applicable generator confidentiality limitations means that the proprietary/sensitive information may be released only to transmission function personnel that are restricted from further disclosure, including to their own merchant functions. Duke also requests clarification that the transmission provider's merchant/generation function and third-parties are to be treated identically as to their right to classify which information that they have given to a transmission provider is proprietary/sensitive, in accordance with Commission policies.

18

Citing

Order No. 890-A at P 148.

Commission Determination

33. The Commission clarifies in response to Duke that, when an affiliate requests information that is already available to the public, the transmission provider need only post a notice that an affiliate requested the particular information, not the actual information. This clarification applies, however, only to those instances in which the actual information is already publicly available.

34. We affirm the requirement that each transmission provider post on a daily basis its load forecast, including underlying assumptions, and actual daily peak load for the prior day.

19

In the NOPR, the Commission specifically raised the possibility of requiring transmission providers to make available their underlying load forecast assumptions for all ATC calculations.

20

The Commission adopted that proposal in Order No. 890, but failed to amend its regulations accordingly.

21

The Commission corrected that oversight in Order No. 890-A.

22

We therefore disagree with Duke that transmission providers were not on notice that posting of load forecast data and related assumptions might be required.

19

18 CFR 37.6(b)(3)(iv) (2007).

20

See Preventing Undue Discrimination and Preference in Transmission Services,

Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,603, at P 194 (2006) (NOPR).

21

See

Order No. 890 at P 416.

22

See

Order No. 890-A at P 143.

35. We clarify, however, that the Commission intended for transmission providers to post the underlying factors used to make load forecasts that have a significant impact on calculations, such as temperature forecasts, not all economic and other data that underlies each and every daily load forecast. Transmission providers must post a description of their load forecast method including how economic and weather assumptions are used in load forecasting. The Commission's intent is to increase transparency in the transmission provider's process of forecasting, providing assurance to customers that loads are consistently being forecast using methodologies which are not subject to daily manipulation to favor affiliates.

36. We also affirm the requirement to make available, upon request and subject to appropriate confidentiality protections and CEII requirements, certain modeling data including load flow base cases and generation dispatch methodology and, subject to additional reasonable and applicable generator confidentiality limitations, production cost models (including assumptions, settings, study results, input data,

etc.

).

23

We clarify in response to Southern that a transmission provider is not required under Order Nos. 890 or 890-A to manufacture or otherwise make available modeling data that it does not use in its ATC calculations. However, if the specified modeling data are used for the calculation of ATC, or any of its components, they must be

made available as required in Order No. 890-A.

23

See

Order No. 890-A at P 148.

37. We agree with Duke that production cost models and generation dispatch methodologies may contain commercially sensitive or proprietary information. Transmission providers are therefore permitted to condition the release of such information on appropriate confidentiality restrictions. With regard to production costs models, reasonable applicable generator confidentiality limitations could include, among other things, restrictions on the release of proprietary and commercially sensitive information to those engaged in the marketing, sale, or purchase of electric power at wholesale. We agree that the transmission provider's merchant and/or generation personnel and third-parties are to be treated identically as to their right to classify proprietary or commercially sensitive information that they provide to a transmission provider, as well as their right to receive such data from the transmission provider.

B. Transmission Pricing

1. Energy and Generation Imbalances

a. Generator Imbalance Penalties

38. In Order No. 890-A, the Commission affirmed the decision in Order No. 890 to adopt standardized generator imbalance provisions in Schedule 9 of the

pro forma

OATT. The Commission clarified 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). Each transmission provider may state on its OASIS the maximum amount of generator imbalance service that 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.

39. The Commission clarified that neither of these options relieves the transmission provider of its obligation to provide generator imbalance service if it is able to acquire additional resources to do so. 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. If no such resources are available, the transmission provider must accept the use of dynamic scheduling to the extent a transmission customer has negotiated an appropriate arrangement with a neighboring control area.

Request for Clarification

40. E.ON U.S. seeks clarification of the time frame within which the transmission provider must post the availability of service (

e.g.

, an hourly, 24-hour, or monthly interval). E.ON U.S. also asks the Commission to clarify the time frame required for obtaining imbalance service from other sources and the extent to which a transmission provider is obligated to seek such resources. E.ON U.S. suggests that this obligation could be interpreted as requiring only a single search or a constant search for resources over a long period of time. E.ON U.S. seeks further clarification regarding the point in the process when the transmission provider must inform the generator that it must arrange for dynamic scheduling because no other option is available.

Commission Determination

41. The Commission affirms the decision in Order No. 890-A to allow a transmission provider to post on its OASIS the maximum amount of generator imbalance service it is able to offer without impairing reliability.

24

To the extent necessary, we clarify that a transmission provider must post the availability of generator imbalance service and seek imbalance service from other sources in a manner that is reasonable in light of the transmission provider's operations and the needs of its imbalance customers. What is reasonable for some imbalance customers and transmission providers may be unreasonable for others. We therefore decline to set a specific time frame within which the transmission provider must post the availability of generator imbalance service. For the same reason, we decline to set a generic time frame for obtaining imbalance service from other sources in the event it is not physically feasible to offer generator imbalance service using the transmission provider's resources.

24

Order No. 890-A at P 289.

42. In the event that there are no additional resources available to enable the transmission provider to meet its obligation to provide generator imbalance service, the transmission provider must accept the use of dynamic scheduling by a transmission customer.

25

The transmission provider cannot, however, require the use of dynamic scheduling, since the customer may choose to make other alternative comparable arrangements to self supply generator imbalance service. If a customer chooses to use dynamic scheduling in this circumstance, it is the option and the responsibility of the transmission customer to seek out and appropriately negotiate dynamic scheduling with a neighboring control area. The transmission provider is required to accommodate the use of dynamic scheduling only to the extent the transmission provider is unable to provide generator imbalance service and the customer has negotiated appropriate arrangements with the relevant control areas.

25

Id.

P 290.

b. Definition of Incremental Cost

43. In Order No. 890-A, the Commission granted rehearing of its decision to calculate incremental costs for the purpose of assessing imbalance charges based on the last 10 MW dispatched to supply the transmission provider's native load. The Commission determined 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. Accordingly, the Commission modified 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 an off-system sale.

Requests for Rehearing and Clarification

44. EEI and Southern argue that the Commission mistakenly used “

i.e.

” instead of “

e.g.

” when referring to the costs to be included in the calculation of charges for energy imbalance service and generator imbalance service. EEI contends that the specified purposes exclude costs to serve other customers, such as on-system customers who take partial requirements service from the transmission provider. EEI asks the Commission to clarify that it meant to use “

e.g.

” to indicate that the list of examples provided were non-exclusive. Southern similarly requests that Schedules 4 and 9 of the

pro forma

OATT be revised to use “

e.g.

” instead of “

i.e.

”

Commission Determination

45. The Commission grants rehearing of the definition of incremental cost as described in the preamble of Order No. 890-A and in Schedules 4 and 9 of the

pro forma

OATT. Those schedules define incremental cost and decremental cost as “the Transmission Provider's actual average hourly cost of the last 10 MW dispatched for any purpose.”

26

We agree that use of the term “

e.g.

” instead of “

i.e.

” when referring to the types of energy to be included in the incremental cost calculation better reflects the Commission's intent to include within that calculation the last 10 MW dispatched for any purpose. We revise the

pro forma

OATT accordingly.

27

26

Schedules 4, 9 of the

pro forma

OATT.

27

We note in response to EEI, however, that the existing reference to native load in Schedules 4 and 9 already includes on-system customers taking requirements service under section 1.23 of the

pro forma

OATT.

2. Credits for Network Customers

46. In Order No. 890-A, the Commission affirmed its decision in Order No. 890 to sever the link in the

pro forma

OATT between joint planning and credits for new facilities owned by network customers. As the Commission explained in Order No. 890, the linkage between credits and joint planning gave the transmission provider an incentive to deny coordinated planning to avoid granting credits for customer-owned facilities. The Commission concluded that any efficiencies that may be lost by severing that link should be offset by the increased efficiencies resulting from the coordinated planning reforms adopted in Order No. 890, which the Commission noted will ensure that most, if not all, transmission facilities are planned on a coordinated basis.

47. The Commission similarly affirmed the decision to adopt a revised test to determine whether a network customer is eligible to receive credits for new facilities. Under the revised section 30.9 of the

pro forma

OATT, customers are eligible for credits for those facilities that are integrated with the operations of the transmission provider's facilities; provided, that integration will be presumed for customer-owned 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. The Commission clarified in Order No. 890 that this revision did not alter the underlying integration standard. In order to satisfy the integration standard, the customer must show that its new facility is integrated with the 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.

28

28

Order No. 890 at P 754, n. 436 (citing

Southwest Power Pool, Inc.,

108 FERC ¶ 61,078 (2004),

reh'g denied,

114 FERC ¶ 61,028 (2006)).

48. The Commission explained in Order No. 890-A that adoption of the presumption of credits in section 30.9 was necessary to ensure comparability between network customers and transmission providers serving load. To that end, the Commission clarified that the presumption of integration is rebuttable as applied to both the transmission provider and the network customer. A transmission provider may challenge the presumption that the customer's facilities are integrated by showing that the customer's facilities do not actually meet the integration standard, notwithstanding the fact that they are similar to facilities in the transmission provider's rate base. Similarly, a customer could challenge the presumption that a transmission provider's facilities are integrated by showing that the facilities, for example, do not provide network benefits. As a result, the Commission clarified 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.

Requests for Clarification and Rehearing

49. NRECA and TAPS ask the Commission to clarify whether it intended to apply a single integration standard to both transmission customer and transmission provider facilities and, if so, what standard will apply. These petitioners contend that several passages in Order No. 890-A suggest that the Commission will now apply a single integration standard, no matter whose facilities are under consideration. They note, for example, the Commission's statement in paragraph 353 of Order No. 890-A that “[a] transmission provider may overcome the network customer's presumed integration by demonstrating, with reference to its own facilities that meet the integration standard, that the network customer's facilities do not meet the standard.”

29

They point to another statement that it is “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.”

30

These petitioners express concern, however, regarding the Commission's statement that the integration standard for credits under section 30.9 remains unchanged and that precedents applying that standard will continue to apply. They argue that those precedents establish and apply a significantly more stringent test for integration of customer-owned facilities than for facilities of the transmission provider.

31

29

Order No. 890-A at P 353.

30

Id.

P 354.

31

Citing East Texas Elec. Coop., Inc.

v.

Central & South West Services, Inc.

108 FERC ¶ 61,079 (2004),

reh'g denied,

114 FERC ¶ 61,027 (2006) (ETEC);

Northeast Tex. Elec. Coop., Inc.,

108 FERC ¶ 61,108, at P 48 (2004),

reh'g denied,

111 FERC ¶ 61,189 (2005) (NTEC).

50. TAPS suggests that the Commission's new policy for new transmission facilities must mean one of three things. Its first and preferred possibility is that, in assessing whether the new integration presumption has been overcome, the Commission will apply a single integration standard to both the transmission provider and the transmission customer,

i.e.

, the relaxed standard that has long applied in determining whether a transmission provider's facilities should be rolled into its rate base. Under a second possibility, a single integration standard also would apply, but transmission providers would be held to the same strict integration standard to which transmission customers seeking section 30.9 credits have long been subject. As a final interpretation, TAPS states that, to overcome the presumption applicable to new transmission facilities, the Commission could continue to apply two different tests: The more stringent one applicable to customers seeking credits and the more relaxed one for transmission providers to include facilities in rate base. TAPS notes, however, that this would be inconsistent with Order No. 890-A's repeated references to a single, comparable integration standard that applies to both customer and transmission providers.

51. East Texas Cooperatives agree that the case law establishes a different and harder test for integration of customer-owned facilities. East Texas Cooperatives state that, under that precedent, a transmission provider needs only to run the load flow study used in ETEC to challenge credits for a customer-owned facility. East Texas Cooperatives argue that this load flow study cannot be satisfied by any transmission facilities, since it takes out both customer facilities and load and asks if the grid can still run reliably. In comparison, East Texas Cooperatives

contend that the cost of transmission provider facilities would continue to be presumptively rolled in subject to challenge unless a party can show that those facilities are so isolated from the grid that they are and will likely remain non-integrated and thus provide no benefit to the system.

52. East Texas Cooperatives therefore argue that the Commission's statement in Order No. 890-A regarding the continued applicability of integration precedent mandates discrimination in favor of transmission provider facilities in violation of the FPA. They contend that eligibility for rolled-in rate treatment of the same facilities would vary solely as a result of their ownership, since customer-owned facilities that are found not to be integrated under a load flow integration test would become integrated if purchased by the transmission provider, which is subject to a more relaxed application of the integration standard. East Texas Cooperatives suggest that the Commission justified its application of a more difficult test to network customers on a presumption that the customer-owned facilities are less integrated than transmission provider facilities. Joined by NRECA and TAPS, East Texas Cooperatives argue that customer-owned facilities are built to serve customer loads just as transmission provider facilities are built to serve transmission provider loads. These petitioners contend that there is no basis in the record for presuming that transmission provider facilities are more integrated than customer facilities.

53. FMPA, NRECA and TDU Systems contend that contradictory statements in Order No. 890-A could be read to apply the more stringent integration standard to customer-owned facilities and a more relaxed integration standard for transmission provider facilities.

32

In particular, these petitioners question what standard the Commission was referring to in paragraph 353 of Order No. 890-A when it stated that the transmission provider may overcome the network customer's presumed integration by demonstrating, with reference to its own facilities that meet the integration standard, that the network customer's new facilities do not meet the standard,

i.e.

, the “integration standard” or the “similar in purpose and design” standard. NRECA and TDU Systems argue that the appropriate standard to apply when both claiming and rebutting the presumption of integration is whether the customer's facilities are similar in design and purpose to those of the transmission provider that are in rates.

32

Citing

Order No. 890-A at P 351-52.

54. Florida Power also requests clarification of language in paragraph 353 of Order No. 890-A. Florida Power asks the Commission to confirm that this statement applies only to determine whether the customer is entitled to the presumption in the first place, not to rebut of the presumption once established, and that the standard to which the Commission was referring is whether the customer-owned facilities are similar in design and purpose to facilities owned by the transmission provider that are included in rates. Florida Power also asks the Commission to confirm that the transmission provider could oppose a customer's initial attempt to establish a presumption of credits by showing, by reference to the transmission provider's own facilities that meet the integration standard, that the customer-owned facilities are not similar in design and purpose to facilities owned by the transmission provider that are included in rates.

55. With regard to rebutting the presumption once established, Florida Power requests confirmation that the transmission provider can overcome the presumption by showing that the customer-owned facilities do not meet the integration standard,

i.e.

, that it does not need the network customer's facility to serve the network customer, the transmission provider's other transmission customers, or the transmission provider's retail customers.

33

Florida Power contends that it would not be just and reasonable, or consistent with the cost causation principle, to shift the cost of customer-owned facilities if those facilities do not benefit the transmission provider's system.

33

Citing Southern California Edison Co.,

108 FERC ¶ 61,085, at P 9 n.11 (2004);

Southwest Power Pool, Inc.,

108 FERC ¶ 61,078, at P 18 n.7 (2004),

reh'g denied,

114 FERC ¶ 61,028 (2006);

ETEC,

108 FERC ¶ 61,079, at P 26 n.11;

Northern States Power Co.,

87 FERC ¶ 61,121 at 61,488 (1999).

56. E.ON U.S. argues that the rebuttable presumption of integration should apply only to customer-owned facilities that are planned through the Attachment K or similar process. If the Commission's expectation that most, if not all, transmission upgrades eligible for credits will be planned in the Attachment K process is true, E.ON U.S. suggests that the rebuttable presumption of integration most reasonably applies only to facilities planned through that process.

34

E.ON U.S. contends that linking credits for customer-owned facilities to the Attachment K planning process would allow the transmission provider an opportunity to coordinate with customers on facilities, while preventing any opportunities for undue discrimination given the non-discretionary nature of the planning obligation. E.ON U.S. argues that failure to plan facilities through the Attachment K or similar process should trigger a presumption against receiving credits for such facilities.

34

Citing

Order No. 890-A at P 426.

57. Several petitioners request rehearing of the Commission's determination that denial of credits for a network customer would no longer trigger a need for the transmission provider to demonstrate that its own facilities satisfy the integration standard. East Texas Cooperatives contend that this decision improperly reverses the approach adopted in

FP&L

35

and prohibits a network customer from challenging the rolled-in rate treatment of transmission provider facilities even when the customer's own facilities are found ineligible for credits. TAPS contends that reversing this policy is inconsistent with notions of comparability unless the Commission clarifies, as requested above, that the relaxed integration standard applies to both network customers and transmission providers. If a network customer's facilities are disqualified from eligibility for credits due to application of a more stringent integration standard, TAPS and TDU Systems argue that comparability requires the removal of the transmission provider's similar facilities from rates. NRECA agrees, arguing that the transmission provider must be required to remove its facilities from rates if customer-owned facilities that are similar in design and purpose to those transmission provider facilities are found ineligible for credits under the integration standard.

35

Florida Mun. Power Agency

v.

Florida Power and Light Co.,

74 FERC ¶ 61,006, at 61,010 (1996),

reh'g denied,

96 FERC ¶ 61,130, at 61,544-45 (2001),

aff'd sub nom. Florida Mun. Power Agency

v.

FERC,

315 F.3d 362 (D.C. Cir. 2003) (

FP&L

).

58. TAPS and FMPA ask the Commission to clarify that removal of the trigger applies only to denial of credit for new facilities to which the new presumption of integration applies. TAPS and FMPA point to language in paragraph 352 of Order No. 890-A providing that “the 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.” Both FMPA and TAPS interpret this language as applying to new facilities only. TAPS contends that the Commission does not and cannot offer any justification for

dispensing with the trigger in cases involving requests for credits for existing facilities, in which the presumption of integration adopted in Order No. 890 does not apply. TAPS is concerned that transmission providers will seek to remove the trigger for existing facilities, relying,

inter alia,

on the more general reference in Order No. 890-A to elimination of trigger.

59. Finally, FMPA seeks clarification on how the Commission's determinations on transmission credits will affect pending cases. FMPA asks the Commission to confirm that Order No. 890-A will not be applied to deny or weaken the comparability requirement for facilities at issue in Docket No. ER93-465-000,

et al.

FMPA also asks the Commission to clarify that the transmission credit policy articulated in Order No. 890 and Order No. 890-A will not preclude FMPA's ability to obtain full relief if the D.C. Circuit remands the Commission's decisions at issue in

Fla. Mun. Power Agency

v.

FERC

regarding charges for transmission that a network customer is physically unable to use.

36

36

No. 06-1285 (D.C. Cir. filed July 26, 2006).

Commission Determination

60. The Commission affirms the decision in Order Nos. 890 and 890-A to revise the test for determining whether a network customer is eligible to receive credits for new facilities. Under the revised section 30.9 of the

pro forma

OATT, a network customer is eligible for credits if it demonstrates that its facilities are integrated with the operations of the transmission provider's facilities, provided that integration will be presumed for new customer-owned 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. As the Commission explained in Order No. 890-A, the adoption of this presumption ensures comparability between network customers and transmission providers serving native load given that transmission providers are now obligated to plan their systems on an open and coordinated basis.

37

37

See

Order No. 890-A at P 350.

61. Several petitioners question how this revised test is consistent with the Commission's statements that the integration standard applicable to new facilities remains unchanged and that Commission precedent regarding application of that standard will continue to apply.

38

As these petitioners note, the integration standard has historically been applied differently to network customers and transmission providers.

39

Transmission facilities owned by the transmission provider enjoyed a presumption of rolled-in rate treatment so long as any degree of integration was shown, while network customers were required to demonstrate affirmatively that their facilities were relied upon by the transmission provider to provide service to its customers.

40

The Commission therefore described the test for integration for network customer facilities as being more stringent than the test applied to transmission provider facilities.

41

The application of the integration standard was, in fact, more stringent as applied to network customers because they did not enjoy the benefit of presumed integration, as did the transmission provider. The underlying integration standard, however, has been and continues to be the same for all transmission facilities. Only those facilities that are, in fact, integrated with the transmission grid and used by the transmission provider to serve customers should be subject to rolled-in rate treatment. It is in this sense that the precedent continues to apply, providing guidance regarding the treatment of facilities that benefit from the presumption of integration and those that do not.

38

See

Order No. 890-A at P 349.

39

Compare Utah Power & Light Co.,

27 FERC ¶ 61,258, at 61,485-87 (1984),

reh'g denied,

28 FERC ¶ 61,088, at 61,165 (1984) (

citing Utah Power & Light Co.,

Opinion No. 113, 14 FERC ¶ 61,112,

reh'g denied,

15 FERC ¶ 61,076 (1981))

with ETEC,

114 FERC ¶ 61,027 at P 42.

40

NTEC,

111 FERC ¶ 61,189 at P 17.

41

Id.

P 15.

62. The presumption of integration enjoyed by the transmission provider has never been absolute. Customers have always been able to challenge the inclusion of certain transmission provider facilities by showing that the facilities did not actually provide a systemwide benefit to the transmission grid.

42

In most instances, however, this has not been the case given that the transmission provider generally plans, constructs and owns its facilities, from the very beginning, to meet delivery obligations, which justifies the presumption of integration.

43

In the event the transmission provider denied credits to a network customer, however, the transmission provider lost the benefit of the presumption and the same integration standard applied to customer-owned facilities was applied to the transmission provider's facilities.

44

This again demonstrates that the same underlying integration standard has applied to all facilities, regardless of ownership, notwithstanding the presumed integration generally enjoyed by the transmission provider.

42

See Idaho Power Co.,

3 FERC ¶ 61,108 (1978),

reh'g denied,

5 FERC ¶ 61,009 (1978);

Minnesota Power & Light Co.,

16 FERC ¶ 63,012 (1981),

aff'd

21 FERC ¶ 61,233 (1982).

43

See Niagara Mohawk Power Corp.,

42 FERC ¶ 61,143, at 61,531 (1988);

Otter Tail Power Co.,

12 FERC ¶ 61,169, at 61,420 (1980).

44

See Florida Power & Light Co.,

105 FERC ¶ 61,287, at P 16 (2003).

63. In light of the planning-related reforms implemented in Order No. 890, the Commission determined it is now appropriate to grant the same presumption of integration to new customer-owned facilities that are similar in scope and design to those transmission provider facilities that are in rates. Implementation of planning-related reforms will now ensure that most, if not all, transmission facilities are planned on a coordinated basis.

45

However, only those new customer-owned facilities that are similar in design and purpose to the transmission provider's facilities that are in rates will be eligible for the presumption of rolled-in rate treatment. Other customer-owned facilities will be eligible for credits only if the network customer is able to make an affirmative showing that the facilities satisfy the integration standard,

i.e.

, that the facilities are nonetheless integrated notwithstanding their ineligibility for the presumption of integration.

46

45

See

Order No. 890 at P 736; Order No. 890-A at P 337.

46

See, e.g., Ne. Tex. Elec. Coop., Inc.,

111 FERC ¶ 61,189 at P 16.

64. To be clear, if the transmission provider disagrees that the customer-owned facilities are similar in design and purpose to its own facilities, it may challenge the threshold application of the presumption with a comparative analysis of its facilities and those for which credits are claimed. Neither the transmission provider nor the network customer need analyze complete satisfaction of the integration standard in order to determine whether, as a threshold matter, the presumption of integration applies. Assuming that the network customer prevails in its claim for presumed integration, then the network customer will enjoy the same rolled-in rate treatment enjoyed by the transmission provider for its similar facilities. As the Commission explained in Order No. 890, this is appropriate to ensure comparability between the transmission provider and network customer now that all transmission facilities will be planned pursuant to an open and coordinated process.

47

47

Order No. 890 at P 435.

65. The transmission provider may nevertheless overcome the presumption of integration by demonstrating, with reference to its own facilities that meet the integration standard, that the customer-owned facilities are not, in fact, integrated and do not provide benefits to the system. The same is true of transmission provider facilities previously presumed to be integrated. In either case, the challenging party will bear the burden in overcoming the presumption of integration and rolled-in rate treatment. It is for this reason that it would no longer be appropriate to remove the presumption of integration enjoyed by the transmission provider,

i.e.

, apply the more strict integration standard, upon denial of credits to a network customer. In the past, only the transmission provider enjoyed the presumption of integration, which justified elimination of the presumption in the event credits were denied to a network customer. Both transmission providers and network customers now enjoy the benefits of presumed integration, and both may challenge application of the presumption to each other's facilities. We continue to believe that this will ensure that all similar facilities that are, in fact, not part of the integrated network that serves all customers are excluded from rates.

48

We acknowledge that this approach departs from the approach adopted in

FP&L

.

49

Our departure is justified, however, because the presumption of integration is now shared with new customer-owned facilities, shifting to the transmission provider the burden of demonstrating that credits for similar customer-owned facilities are not warranted.

48

See

Order No. 890-A at P 351.

49

FP&L,

74 FERC at 61,010 (finding that the integration of facilities into the plans or operations of a transmitting utility is the proper test for cost recognition).

66. We reject the suggestion by E.ON U.S. to reestablish a link between credits and joint planning by applying the presumption of integration only to upgrades planned through the transmission provider's Attachment K process. Although we support coordinated, open, and transparent planning, transmission providers are not required to develop transmission plans on a co-equal basis with customers.

50

It would therefore be unfair to network customers to condition the receipt of credits for new facilities on planning activities that are out of their control. Indeed, restablishing a link between joint planning and credits would revive disincentives the Commission sought to correct by severing the link between planning and credits in Order No. 890. We therefore affirm our decision to sever the link between credits and joint planning.

50

Order No. 890-A at P 188.

67. To the extent necessary, we clarify that none of the reforms regarding transmission credits adopted in Order No. 890 were intended to apply to facilities existing prior to the effectiveness of the revised section 30.9 nor to pending cases involving such facilities. Denial of credits to a network customer's previously existing facilities therefore still triggers review of the transmission provider's rate base. Similarly, a network customer may not rely on the presumption of integration for its previously existing facilities.

3. Capacity Reassignment

68. In Order No. 890-A, the Commission granted rehearing of its decision in Order No. 890 to remove the price cap on reassignments of transmission capacity, concluding that it is more appropriate to allow reassignments above the cap only during a study period ending on October 1, 2010. The Commission directed staff to closely monitor the development of the secondary market for transmission capacity during this period. To assist staff in this effort, the Commission affirmed the requirement for transmission providers to aggregate and summarize in an electronic quarterly report (EQR) the data contained in service agreements and related OASIS schedules for reassigned capacity. The Commission also directed staff to prepare a report on staff's findings within 6 months of the receipt of two years worth of data,

i.e.

, by May 1, 2010. Upon review of the staff report and any feedback from the industry, the Commission will determine whether it is appropriate to continue to allow reassignments of capacity above the price cap beyond the study period. In the absence of further Commission action, the price cap will resume effect as of October 1, 2010 under section 23.1 of the

pro forma

OATT.

69. The Commission clarified in Order No. 890-A 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. As a result, there is no longer a need for the assigning party to have on file with the Commission a rate schedule governing reassigned capacity. To the extent that a reseller has a market-based rate 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.

Request for Rehearing

70. The APPA Joint Filers argue on rehearing that the decision to remove the price cap for reassignments of transmission capacity during the study period is not supported by substantial evidence that the price cap has discouraged development of a secondary transmission market.

51

The APPA Joint Filers also contend that lifting the price cap on reassigned capacity will harm consumers by making transmission artificially scarce and overpriced. The APPA Joint Filers argue that the existence of congestion creates constrained regions within which market power can be exercised.

51

The APPA Joint Filers include: APPA, NRECA, TAPS and TDU Systems.

71. To further protect consumers, the APPA Joint Filers suggest that the Commission limit the experimental lifting of price caps to short-term reassignments.

52

The APPA Joint Filers state that long-term firm point-to-point transmission service is particularly important to LSEs looking to secure economic and reliable power supply and that non-firm releases of unscheduled transmission capacity will not help those LSEs needing long-term firm service. The APPA Joint Filers also argue that, by extending the experiment to long-term sales, including reassignments by the transmission provider's merchant function or affiliate, the Commission has discouraged needed transmission construction. If the secondary market is clearing at prices above the transmission provider's rate ceiling, the APPA Joint Filers contend that the parent corporation will have incentives to put as much capacity in the hands of its merchant function or affiliates as possible and to avoid new transmission construction. That result, the APPA Joint Filers argue, would reduce the access of LSEs to the long-term firm transmission service they require to meet their service obligations, in violation of FPA section 217(b)(4). The APPA Joint Filers suggest that the Commission can achieve its goal of determining whether the price cap encourages development of a secondary market and whether there is competition in such a market by lifting the price cap only for short-term reassignments.

52

Citing Interstate Natural Gas Ass'n of Am.

v.

FERC,

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

72. The APPA Joint Filers also contend that the affirmative obligation

of the transmission provider to expand its system in order to accommodate requests for service is inadequate to ensure customers are protected. The APPA Joint Filers note that this obligation has existed since 1996, yet the Commission in Order No. 890 found that it had not succeeded in overcoming transmission providers' incentives to avoid transmission investment, especially in favor of their own generation.

53

The APPA Joint Filers contend that the Commission has no factual basis to conclude that entry in the form of expanded transmission capacity will be timely, likely and sufficient to defeat price increases due to transmission market power.

53

Citing

Order No. 890 at P 424.

73. The APPA Joint Filers acknowledge that Commission staff will be monitoring the EQRs and other data during the two-year period with the goal of preparing its report, but argue that this does not alleviate the Commission of its obligation to actively monitor resale of transmission capacity during the period to ensure that rates for customers remain just and reasonable and that there are no abuses of market power. The APPA Joint Filers ask the Commission to explicitly establish its intent to continue to exercise its obligations under sections 205 and 206 throughout this period so that resellers are on notice that they cannot charge unjust and unreasonable rates. If the Commission discovers evidence of unjust and unreasonable rates at any time, the APPA Joint Filers urge the Commission to address this as it occurs, including if necessary by terminating the experiment prior to October 1, 2010.

74. With regard to the staff report, the APPA Joint Filers ask the Commission to prescribe the parameters, procedures and data to be collected and provide guidance as to the issues that should be addressed. The APPA Joint Filers suggest that the Commission direct staff to address the following specific matters in the report: Identify whether there is an increase in reassignments by examining data on the amount of reassignments before and after the price caps were lifted; examine prices both offered and accepted to determine the level of market interest in reassigned capacity, whether prices increased, the cause of price changes, and whether prices remained within a zone of reasonableness; examine whether competition among resellers is sufficient to protect consumers from excessive rates; identify the kinds of products resold, such as the length of reassignments and whether reassigning customers redirected service; consider whether reservations by the transmission provider's merchant function or affiliates increased, whether they reassigned the capacity reserved, and to whom and at what price they reassigned service; indicate whether the transmission provider's interactions with affiliated resellers were covered by the Standards of Conduct; and, assess whether those needing transmission capacity were able to obtain it, whether in the primary or secondary market.

75. To the extent the EQR data or other sources do not provide this information, the APPA Joint Filers suggest that the Commission institute data reporting and collection requirements to obtain that information. The APPA Joint Filers state particular concern regarding the elimination of the reporting requirement under the reseller's market-based rate tariff. The APPA Joint Filers contend that lifting the price cap will allow market-based sellers to use transmission capacity reassignment to support attempts to exercise market power in sales of transmission, electricity, or both. Because a market-based seller no longer needs to report its own transmission reassignments and because the transmission provider will report reassignments only on an aggregate, summary basis, the APPA Joint Filers argue that the EQR data will not permit monitoring to detect patterns or conduct that suggest efforts to manipulate or exercise market power in transmission markets. The APPA Joint Filers contend that, by separating data on the market-based seller's electricity sales from the data on the same seller's transmission reassignments, the Commission has made it difficult to determine whether a market-based seller is manipulating transmission resales to favor its market-based sales because it will be impossible to determine whether a particular capacity reassignment supported a market-based sale. The APPA Joint Filers therefore request that the Commission grant rehearing and retain the requirement that all holders of market-based rate authority report both their electricity sales and their capacity reassignments in the same EQR.

76. Finally, once the staff report is issued, the APPA Joint Filers ask that it be noticed and that the public be provided an opportunity to comment. The APPA Joint Filers contend that the data underlying the report must be made public, with sensitive information subject to appropriate confidentiality protections. If the Commission believes that further extension of the experiment is merited, the APPA Joint Filers ask the Commission to use full notice and comment rulemaking procedures to ensure a complete record is developed to support any further Commission action.

Commission Determination

77. The Commission affirms its decision to remove the price cap on reassignments of transmission capacity to accommodate a study period expiring on October 1, 2010. For the reasons stated in Order Nos. 890 and 890-A, we continue to believe that lifting the price cap during the study period will foster the development of a more robust secondary market for transmission capacity.

54

Point-to-point transmission service customers will have increased incentives to make their service available to others that place a higher value on it, which in turn will send more accurate signals that promote efficient use of the transmission system by fostering the reassignment of unused capacity.

54

Order No. 890 at P 808; Order No. 890-A at P 388-89.

78. Although the Commission agrees with the APPA Joint Filers that transmission capacity, and in particular long-term transmission capacity, is of great importance to LSEs and other customers, we disagree that restricting transactions above the price cap only to short-term reassignments is necessary to preserve access to service under the

pro forma

OATT. As the Commission emphasized in Order Nos. 890 and 890-A, transmission providers are under an affirmative obligation to offer all available capacity to customers on a non-discriminatory basis and to expand their systems as necessary to accommodate additional requests for service.

55

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. The fact that a transmission provider's affiliate may profit from congestion on the system does not relieve the transmission provider of its obligation to offer all available transmission capacity and expand its system as necessary to accommodate requests for service. We therefore disagree that allowing reassignments of transmission capacity above the price cap will reduce the access of any customer to service under the

pro forma

OATT.

55

Order No. 890 at P 814; Order No. 890-A at P 392.

79. The APPA Joint Filers are therefore incorrect that lifting the price cap will make transmission capacity

artificially scarce and overpriced during the study period. Transmission providers must continue to make primary capacity available at the rates specified in their individual OATTs. Customers that do not wish to participate in the secondary market may continue to take service from the transmission provider directly, just as if the price cap had not been lifted. For those customers participating in the secondary market, however, lifting the price cap will create additional incentives for others to make service available, increasing the ability to obtain transmission capacity.

80. The APPA Joint Filers incorrectly characterize the Commission's statement in paragraph 392 of Order No. 890 as finding that the transmission provider's obligation to expand the system in response to service requests was inadequate to overcome incentives to avoid transmission investment. In the passage cited, the Commission instead found that this requirement was inadequate to overcome incentives to exclude customers from the transmission planning process.

56

56

Id.

P 424.

To remedy that disincentive, the Commission required transmission providers to implement open and transparent planning processes that allow customers and other stakeholders to provide input in the development of transmission plans. The Commission specifically noted that those planning obligations did not address or dictate which investments identified in a transmission plan should be undertaken by the transmission provider.

57

57

Id.

P 438.

81. The APPA Joint Filers inappropriately discount the importance of the transmission provider's affirmative obligation to expand its system in response to requests for service. The Commission has historically relied on these and other obligations under the pro forma OATT sufficient to mitigate the potential exercise of transmission market power by transmission providers and their affiliates.

58

Lifting the price cap on reassignments of transmission capacity does not alter those obligations in any way and, therefore, does not impair the ability of load-serving entities to meet their load service obligations. By lifting the price cap on capacity reassignments, the Commission has instead enhanced the options available to customers seeking transmission service by increasing the incentives for customers with transmission reservations to make capacity available to others placing a higher value on it.

58

See

Order No. 697 at P 408.

82. We are nevertheless sensitive to the concerns expressed regarding the potentially negative competitive effects of lifting the price cap on reassignments of transmission capacity. It is for that very reason that the Commission granted rehearing in Order No. 890-A, at the request of the APPA Joint Filers, to limit the period in which the price cap is lifted. During the study period, 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 other regulatory controls, will assure that prices in the secondary market remain within a zone of reasonableness.

59

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 mechanisms. If the Commission finds evidence of market abuse, it can act to restrict the ability of an offending reseller (and possibly its affiliates) to participate in the secondary market or impose other remedies, including civil penalties, as appropriate to ensure that rates for secondary transmission capacity are just and reasonable.

59

See

Order No. 890 at P 811; Order No. 890-A at P 391.

83. With respect to our expectations for the report to be prepared by Commission staff, we clarify that staff should focus on the competitive effects of removing the price cap for reassigned capacity. Staff should consider the number of reassignments occurring over the study period, the magnitude and variability of resale prices, the term of the reassignments, and any relationship between resale prices and price differentials in related energy markets. Staff should also examine the nature and scope of reassignments undertaken by the transmission provider's affiliates and include in its report any evidence of abuse in the secondary market for transmission capacity, whether by those affiliates or other customers.

60

60

See id.

P 406.

84. As requested by the Joint APPA Filers, we have reconsidered our reporting requirements and determined that it would be useful to direct transmission providers to include certain additional information in their EQRs. We direct transmission providers to include in their EQRs the identity of the reseller and indicate whether the reseller is affiliated with the transmission provider. Each transmission provider also must include the rate that would have been charged under its OATT had the secondary customer purchased primary service from the transmission provider for the term of the reassignment. We direct transmission providers to submit this additional data for all resales during the study period and to update, as necessary, any previously-filed EQRs on or before the date they submit their next EQR.

85. We disagree that elimination of the reporting requirement under the reseller's market-based rate tariff will impair the ability of staff to perform its analyses. All reassignments of transmission capacity now take place under the transmission provider's OATT and, therefore, it is appropriate for the transmission provider to report those transactions on its EQR. We reiterate that the EQR must contain all relevant transaction data, whether stated in the service agreement governing the reassignment or in a related OASIS schedule.

61

Transmission providers should not aggregate multiple transactions into single line items on the EQR. All terms must instead be fully described and rates provided for each reassignment.

62

61

See

Order No. 890 at P 423, n.162.

62

See

Order No. 890 at P 818, n.499. The Commission's reference to “aggregate[ing] and summarize[ing] in an EWQ the data contained in the service agreements for reassigned capacity” in Order Nos. 890 and 890-A was intended to refer to the transmission provider's obligation to compile reassignments involving multiple parties in a single EQR, not consolidate multiple reassignments into single line items on the EQR.

86. Upon review of the staff report, the Commission will determine whether it is appropriate to institute further rulemaking procedures to amend the

pro forma

OATT to allow reassignments of transmission capacity above the price cap after October 1, 2010. The report will be made public and subject to comment, with sensitive information subject to appropriate confidentiality protections. In the absence of Commission action, the rate charged by the transmission provider for each reassignment, and the corresponding credit to the reseller, may 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.

63

63

See

section 23.1 of the

pro forma

OATT.

4. Operational Penalties

87. In Order No. 890-A, the Commission affirmed the decision in Order No. 890 to subject all transmission providers, including RTOs and ISOs, to operational penalties when they routinely fail to meet the deadlines prescribed in sections 19.2, 19.4, 32.3 and 32.4 of the

pro forma

OATT. The Commission explained that the 60-day due diligence deadlines set forth in those sections serve as a good measure of a transmission provider's use of due diligence since, in its experience, the vast majority of transmission studies can be completed in that time period.

88. The Commission rejected requests to change section 19.9 of the

pro forma

OATT, concluding that transmission providers will have the ability to explain in notification filings the extenuating circumstances that lead to delay in processing transmission service request studies and, in turn, demonstrate their use of due diligence notwithstanding the inability to meet the 60-day target. The Commission also rejected requests to create broad categories or lists of extenuating circumstances that would exempt transmission providers from late study penalties or related posting requirements.

Requests for Rehearing and Clarification

89. E.ON U.S., EEI, and Southern contend that the Commission has failed to justify the use of 60 days as the time frame for processing transmission service request studies with due diligence. These petitioners argue that the Commission's stated experience that the vast majority of studies are completed within 60 days is unsupported by data or any other evidence. Southern further argues that any experience regarding processing times does not reflect the increased redispatch and conditional firm study obligations imposed under Order No. 890. Southern argues that transmission planners are also facing additional workforce pressures due to development of reliability standards, worker shortages, and Attachment K planning processes. Southern suggests that the Commission grant rehearing to allow for an additional 30 days to process transmission studies or, at a minimum, to process conditional firm and redispatch options. Southern acknowledges that the Commission determined in Order No. 890-A that the mere possibility of penalties did not justify extension of the 60-day study period. Southern argues, however, that the notification and additional posting requirements are in and of themselves penalties, as are the requirements to then complete 90 percent of studies within 60 days.

90. E.ON U.S., EEI, and Southern also ask the Commission to add a clearer due diligence standard to section 19.9 of the

pro forma

OATT. They contend that it is necessary to specify in the tariff the circumstances that will excuse the transmission provider from penalties. These petitioners argue that failure to articulate a clear standard gives the Commission too much discretion in applying penalties and leaves transmission providers guessing as to what due diligence means. Southern argues that a lack of clarity violates due process and the Commission's enforcement policies because transmission providers do not have adequate notice of the circumstances that will subject them to penalties. Southern contends that the risk of late study penalties creates a guilty until proven innocent standard that will result in transmission providers favoring speed over accuracy, which could harm reliability.

91. EEI agrees that failure to expressly include a due diligence standard in section 19.9 provides the Commission undue discretion to apply penalties even if the transmission provider has used due diligence in processing request studies. EEI argues that the language of section 19.9 does not adequately reflect that the inability to complete a study within the 60-day timeframe may be due to customer actions or the need to complete other interdependent studies. At a minimum, EEI asks the Commission to amend section 19.9(iii) to state that the transmission provider will not be subject to penalties if it demonstrates that it exercised due diligence but nonetheless failed to complete a sufficient percentage of its studies within 60 days. EEI also requests that the Commission provide additional guidance in this proceeding as to what factors constitute due diligence that are sufficiently clear and specific that a transmission provider can reasonably determine whether its actions satisfy those guidelines.

92. E.ON U.S., EEI, and Southern further argue that operational penalties should not be imposed until the Commission makes an affirmative finding that the transmission provider did not exercise due diligence in processing request studies. EEI and Southern argue that due process and the Commission's enforcement policies require notice and hearing procedures prior to application of penalties. If a transmission provider fails to complete 90 percent of studies within a 60-day period, EEI suggests that the transmission provider be rebuttably presumed to have failed to exercise due diligence in processing request studies and that penalties apply only after notice and an opportunity for hearing.

93. Southern suggests that the explanation of extenuating circumstances in a notification filing should automatically suspend the obligation to post additional metrics, the obligation to process 90 percent of study requests within 60 days, and the threat of monetary penalties until the Commission determines that the extenuating circumstances did not exist. Southern states that this would shift the burden of proof to the Commission and no longer treat transmission providers as guilty until proven innocent. E.ON U.S. argues that deferring the obligation to pay penalties until after the Commission has rejected the transmission provider's explanation for delay would be more efficient because transmission providers would not need to seek refunds from customers to whom it has made distribution of penalties for delays the Commission later finds justifiable.

94. E.ON U.S. seeks clarification that not-for-profit transmission providers are responsible for processing transmission request studies within the same time period prescribed for other transmission providers and are equally responsible for paying late study penalties. E.ON U.S. argues that the ability to request cost recovery of late study penalties on a case-by-case basis should not be used to skirt the obligations established in Order No. 890.

95. NYISO asks the Commission to clarify that it did not intend in Order No. 890-A to preclude transmission providers from proposing alternative study deadlines pursuant to FPA section 205. NYISO states that, because it provides a financial reservation based transmission service reservation, it does not receive, or deny, requests for transmission service in the way that Order Nos. 888 and 890 contemplate. NYISO states it conducts transmission studies only in unusual situations, such as when a customer wants to explore whether it would be more economical to pay congestion charges or to fund the construction of new transmission facilities in order to obtain incremental congestion hedging rights from NYISO. As a result, only a handful of system impact study requests have been submitted to the NYISO in the last nine

years and, according to NYISO, each take substantial time to process.

96. NYISO also requests clarification regarding the transmission provider's liability when delegating responsibilities for conducting transmission studies. NYISO states that it has responsibility for conducting system impact studies under its OATT, while its member transmission owning utilities retained responsibility for conducting facilities studies. NYISO asks the Commission to clarify that its member transmission owning utilities are responsible for ensuring that facilities studies are conducted in a timely manner. NYISO argues that it would be arbitrary and capricious to hold NYISO responsible for failures by the member transmission-owning utilities to comply with their own obligations.

Commission Determination

97. The Commission affirms the decision in Order Nos. 890 and 890-A 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.

64

Transmission providers must have a meaningful stake in meeting study timeframes, and the operational penalty structure adopted by the Commission provides reasonable financial incentives for transmission providers to exercise due diligence in processing service requests in a timely and nondiscriminatory manner.

64

See

Order No. 890 at P 1340; Order No. 890-A at P 741.

98. We disagree that the notice procedures adopted in Order No. 890 give inadequate opportunities to explain why studies have been completed late. Due process does not require the use of notice and hearing procedures prior to applying operational penalties for failing to exercise due diligence in processing transmission service request studies within the 60-day study period, nor must the Commission make an affirmative finding regarding the justifications provided in a notification filing prior to the application of penalties. Section 19.9 of the

pro forma

OATT requires the submission of a notification filing and the application of penalties when certain clearly identified triggering conditions occur,

i.e.

, failure to complete studies within the prescribed timeframes. Transmission providers therefore have adequate notice of the actions that may lead to penalties. We note that transmission customers that pay other operational penalties, like unreserved use penalties, do not receive notice or have hearing procedures prior to paying the penalty.

99. At the same time, to ensure that penalties are not applied to transmission providers when study delays are justified, the Commission has provided an opportunity for each transmission provider to explain the extenuating circumstances that prevented it from meeting the 60-day study completion deadline. Upon review of the notification filing, the Commission will waive the penalties if a transmission provider establishes that its non-compliance is the result of extenuating circumstances.

65

If the Commission is unable to act on the notification filing prior to the date on which the penalties would apply, the transmission provider will remain liable for paying the penalties, but is not required to distribute those penalties while the notification filing remains pending.

66

The Commission concluded in Order No. 890, and we affirm here, that this adequately balances the transmission provider's due process rights with the need to provide an incentive to the transmission provider to complete studies on a timely basis.

67

It is therefore unnecessary, as petitioners argue, to amend the language of section 19.9 of the

pro forma

OATT to specifically include a due diligence standard or otherwise identify in the tariff or elsewhere the circumstances that will excuse the transmission provider from penalties. Consideration of the particular extenuating circumstances causing a transmission provider to repeatedly miss study deadlines is best left to a case-by-case analysis.

65

See

Order No. 890 at P 1343.

66

See id.

P 1349.

67

Id.

100. We also affirm the decision in Order No. 890-A not to extend the 60-day deadline as petitioners request.

68

The 60-day deadlines have existed for many years.

69

Although petitioners challenge that conclusion as unsupported, none dispute the proposition that 60 days is generally sufficient to complete most transmission studies and, instead, contend that certain types of studies take longer or that certain transmission providers have less ability to process studies within that period. Yet that is precisely why the Commission has provided an opportunity for each transmission provider to demonstrate that extenuating circumstances prevented it from timely processing the relevant studies notwithstanding its inability to meet the 60-day target. Transmission providers are free to discuss in their notification filings any factors they believe are relevant, including any of the factors cited by Southern.

68

Order No. 890-A P 746.

69

See

Order No. 888-A at 30,324.

101. In response to E.ON U.S., we affirm that all transmission providers, including RTOs and ISOs, are bound by the 60-day timelines of sections 19.2, 19.4, 32.3 and 32.4 and the requirements of section 19.9. The Commission clarifies, in response to NYISO, that transmission providers are free to make filings under FPA section 205 to seek variations from the

pro forma

OATT and demonstrate that alternative tariff provisions are consistent with or superior to the

pro forma

OATT. With regard to the allocation of study responsibilities between NYISO and its transmission owning members, we note that the Commission in Docket No. OA08-13-000 determined that the responsibility for facility studies, and penalties associated with such studies, rests with the transmission owning members under the NYISO tariff.

70

70

See N.Y. Indep. Sys. Operator, Inc.,

123 FERC ¶ 61,134 (2008).

5. “Higher Of” Pricing Policy

102. In Order No. 890, the Commission concluded that changes to the

pro forma

OATT were not needed to address the practice by some transmission providers of quoting incremental rates as lump sum payments, a practice that is inconsistent with our ratemaking policy. The Commission explained that the transmission provider must 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 also must 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.

103. The Commission affirmed this decision in Order No. 890-A, noting 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. The Commission explained that it would not be appropriate to vary capital costs over the term of such contracts.

Request for Rehearing

104. Duke, E.ON U.S., and EEI argue that the Commission's statement that

capital costs of network upgrades may not vary during the term of a service agreement is inconsistent with other sections of the

pro forma

OATT. Duke notes that section 19.4 of the

pro forma

OATT requires execution (or filing) of a service agreement a mere thirty days after completion of the facilities study and, therefore, the service agreement can only contain a good faith estimate of network upgrade costs. EEI and E.ON U.S. agree, noting section 19.5 further allows for revisions to the good faith estimate to reflect certain changed circumstances. EEI and E.ON U.S. contend that transmission providers generally are not able to determine the actual cost of required facilities until construction is completed, which is long after execution of the service agreement.

105. EEI and E.ON U.S. argue that not allowing capital costs of upgrades to vary after execution of the service agreement will result in the transmission provider either under-recovering the cost of the incremental facilities or the customer overpaying the cost of those facilities and, as a result, charges will not be just and reasonable. These petitioners suggest that the transmission provider be allowed to modify a service agreement to reflect the actual costs of incrementally-charged network upgrades after the facilities are placed in service. Duke agrees, arguing that providing for a true-up at a later date is routine when facility costs are directly assigned, rather than rolled in. Duke suggests that customers be free to negotiate the ability to terminate the service agreement if a cost estimate turns out to far understate actual costs. Duke contends that the Commission's statement regarding the inability of capital costs to vary was merely a general observation and that the Commission should review rate changes on a case-by-case basis.

106. Duke, EEI, and E.ON U.S. further argue that prohibiting recovery of additional capital costs that the transmission provider is likely to incur when repairing or replacing portions of incrementally-charged upgrades during the term of a service agreement denies the transmission provider of its rights under section 205 of the FPA. While the incremental facilities on which the cost of service is based (

e.g.

, a specific substation or line segment) should not be allowed to vary, EEI contends that transmission providers should be allowed recover the additional capital costs associated with repair or replacement of those facilities. EEI and E.ON U.S. suggest that remedies such as formula rates or a section 205 filing should be available to a transmission provider to recover these additional costs.

Commission Determination

107. The Commission affirms the determination in Order No. 890 that capital costs specified in a service agreement are not subject to change once the customer has executed the service agreement.

71

We clarify, however, that this statement was intended to refer to agreements in which a customer and transmission provider have specifically identified particular upgrade costs to be paid by the customer, allowing for a clear comparison of incremental costs to the transmission provider's embedded cost rate. In such instances, it would violate fundamental concepts of contract law, as well as undermine the “higher of” pricing policy, to allow either the customer or the transmission provider to unilaterally change the costs previously agreed to by the parties. The Commission therefore explained in Order No. 890-A that it would not be appropriate to vary,

i.e.

, change, capital costs specified in such contracts.

71

See

Order No. 890-A at P 491.

108. Nothing in Order Nos. 890 or 890-A, however, altered the ability of the transmission provider and transmission customer to negotiate alternative pricing arrangements such as recovering estimated costs subject to a true-up when upgrades are complete. The Commission did not mean to imply in Order No. 890-A that such alternative pricing arrangements are necessarily prohibited. As the Commission explained in Order No. 890, application of the “higher of” policy to particular cases, including proposals to adopt flexible pricing arrangements, is largely fact-specific and best addressed on a case-by-case basis during particular rate proceedings.

72

72

See

Order No. 890-A at P 883.

6. Other Ancillary Services

109. In Order No. 890-A, the Commission denied a request by Sempra Global to require the transmission provider 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. The Commission explained that operating reserves are needed to serve load within the control area in the event of system contingencies and, unless alternative arrangements are made, the transmission provider provides these reserves from its own resources. The Commission found that 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 obligations to make operating reserves available. The Commission affirmed those obligations and stated that modifications to the

pro forma

OATT were not necessary to enable generators to engage in firm power sales to loads outside of their control area.

Request for Clarification

110. Sempra Global argues that the Commission did not fully appreciate the problems faced by generators in obtaining operating reserves in the WECC. If transmission providers are not required to offer operating reserves when transmission service is used to serve load outside the transmission provider's control area, Sempra Global asks that the Commission, at a minimum, clarify that generator imbalance service under Schedule 9 of the

pro forma

OATT may be utilized to provide sufficient imbalance energy to keep a customer's schedule whole for at least two hours following a generator derating or forced outage, if necessary to allow the generator sufficient time to find and schedule replacement energy. Sempra Global states that clarification is needed because, if a generator trips within 20 minutes prior to the beginning of the hour, it is too late to schedule replacement energy for the hour that is about to begin.

111. Sempra Global disagrees that the existing requirements of the

pro forma

OATT are sufficient to ensure that operating reserves are available to merchant generators in the WECC, pointing to the differing definitions for “reserves” in the West. Sempra Global explains that in the WECC “Operating Reserves” consist of two main components: Regulating Reserve and Contingency Reserve.

73

According to Sempra Global, WECC's Regulating Reserve could include, but would not necessarily be limited to, regulation service offered under schedule 3 of the

pro forma

OATT, while WECC's Contingency Reserve could include, but would not necessarily be limited to, operating reserve services under Schedules 5 and 6 of the

pro forma

OATT.

73

Citing

WECC Standard BAL-STD-002-0—Operating Reserves.

112. Although independent power generators have access to regulation service under schedule 3 and generator

imbalance service under Schedule 9 from their source balancing authority, Sempra Global states that they may not have access to any Contingency Reserves for exports from their host balancing authority. Sempra Global contends that it can be difficult, if not impossible, for generators to contract for Contingency Reserves from a third party without switching to that party's balancing authority or having a dynamic schedule or other telemetry to enable the provider of Contingency Reserves to know when the generator trips and to have the reserves provider's generation respond within ten minutes. Sempra Global contends that intra-hour schedule changes are not normally allowed by most balancing authorities in the West and that Operating and/or Contingency Reserve service can most logically be provided to a balancing authority or reserve sharing group, not an individual customer. Sempra Global states that this complex type of arrangement could not be practicably implemented for short-term transactions, or when the output of a generator is split between multiple buyers and ultimately delivered into multiple balancing authorities.

113. Even if a generator were able to contract with a third party to provide operating reserves, Sempra Global states that it is unaware of any workable mechanism to assure a load (or “sink”) balancing authority that it will have access to such reserves when needed. Sempra Global also notes that a generator, as a seller, may not necessarily have a load since transactions frequently involve numerous parties between the generator and the load. Sempra Global states that a generator may not know who the load is until the NERC eTags are generated during the WECC pre-scheduling process, which typically takes place the day before the power flows. Even if the sink balancing authority is known at the time a long-term transaction is entered into, Sempra Global states that a generator still may be unable to procure operating reserves to support the transaction. Sempra Global describes a transaction it entered into in 2002 in which none of the host transmission provider, the purchaser's transmission provider, nor the purchaser itself was willing to offer to provide Sempra Global with operating reserves to support the transaction. Since many LSE purchasers in the West enter into firm energy import transactions specifically to reduce their operating reserves obligations, Sempra Global states that it would be rarely fruitful for a generator to request, as part of its negotiation with a customer, that the customer acquire reserves from its transmission provider.

Commission Determination

114. The Commission affirms the decision in Order No. 890-A not to require transmission providers to offer and make available operating reserves under Schedules 5 and 6 of the

pro forma

OATT when transmission is used to serve load outside the transmission provider's control area. As the Commission explained, 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 would serve as the provider of last resort for these reserves. We continue to believe it would be inappropriate to require the transmission provider to provide additional operating reserves to loads in other control areas because the transmission providers in those areas are under their own obligation to make operating reserves available.

115. We appreciate Sempra Global's concern that these obligations may be insufficient to enable merchant generators in the WECC to obtain operating reserves in certain circumstances. Since its adoption, however, the

pro forma

OATT has placed the obligation to procure operating reserves squarely on load.

74

It appears that market rules have developed in the WECC in a way that transfers that responsibility from transmission customers serving load to those providing resources. It does not follow, however, that the

pro forma

OATT—a tariff of general applicability—must be amended to accommodate that regional practice. To the extent transmission providers in the WECC wish to amend their tariffs to accommodate the WECC market rules, they may submit such variations to the Commission for consideration. Alternatively, the market rules themselves could be amended to reflect the structure of obligations under the

pro forma

OATT.

75

74

See

Section 3 of the

pro forma

OATT.

75

We understand that WECC is in the process of developing a revised standard to address the responsibility for procuring contingency reserves. WECC Standard BAL-002-WECC-1—Contingency Reserves, available at

http://www.wecc.biz/documents/library/Standards/2007/BAL-002/BAL-002-WECC-1_1-25-08.pdf.

To the extent that there are any conflicts between the revised WECC standard and the

pro forma

OATT, Sempra Global should raise those concerns when that revised standard is submitted for consideration by the Commission.

C. Non-Rate Terms and Conditions

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

116. 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 modify planning redispatch requirements and require transmission providers, other than most RTOs and ISOs, to offer a conditional firm option to long-term point-to-point customers. The Commission affirmed that decision in Order No. 890-A and provided certain clarifications regarding the transmission provider's obligation with regard to planning redispatch and conditional firm service.

a. Requirement To Offer Conditional Firm Service

117. In Order No. 890-A, the Commission denied rehearing of its decision not to require transmission providers to offer conditional firm service to network customers. The Commission explained that network customers can designate network resources any time firm transmission is available and that 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. The Commission concluded that this flexibility to use designated network resources and secondary network service to access undesignated resources already provides a service that is like conditional firm that can be used to integrate new resources. The Commission noted, however, that transmission providers employ automatic devices, such as special protection schemes, to take resources offline during certain system conditions. The Commission determined that comparability requires the study of these automatic devices for network customers seeking to designate network resources and revised section 32.3 of the

pro forma

OATT to require the study of automatic devices at the request of a network customer.

Requests for Rehearing and Clarification

118. NRECA and TAPS repeat arguments made on rehearing of Order No. 890 that the Commission must make

conditional firm service available to network customers. NRECA contends that a transmission provider will not reject a resource for its own bundled retail load simply because it may be unavailable for a few hours per year due to congestion. NRECA argues that a transmission provider will, however, reject a request by a network customer to designate that same resource because of the same limited availability. NRECA concludes that conditional firm network service is therefore necessary to eliminate undue discrimination between network customers serving network load and the transmission provider serving its load.

119. NRECA acknowledges that network customers may designate network resources any time firm transmission is available and use secondary network service to access resources when firm service is not available. NRECA notes, however, that the Commission justified granting conditional firm service to point-to-point customers by stating that it made little sense to ask point-to-point customers to cobble together a collection of firm and non-firm requests when only the transmission provider has information about when service may be available or unavailable.

76

NRECA argues that network customers should not be required to cobble together service comparable to that enjoyed by the transmission provider by designating a resource at some times and accessing it through secondary network service at others.

76

Citing

Order No. 890 at P 925.

120. NRECA also argues that the Commission improperly assumed that secondary network service can provide a service that resembles conditional firm service. NRECA contends that the curtailment priority of secondary network service is inferior to conditional firm service. NRECA provides a scenario in which the transmission provider, a conditional firm customer and a network customer using secondary network service are taking power from the same generator in a location that is constrained ten hours per year. NRECA argues that the network customer will be curtailed before the transmission owner and before the conditional firm customer. NRECA adds that conditional firm customers are considered firm customers and will be able to request service far in advance and to the detriment of secondary network customers. NRECA concludes that a network customer can only protect itself from loss of service and loss of scheduling priority by paying for a network upgrade, which is an obligation not imposed on either the transmission provider or the point-to-point customer.

121. TAPS agrees that the rights of network customers are significantly inferior to those of conditional firm customers. TAPS contends that a network customer would be required to have perfect knowledge, at the time of a network resource designation, as to the effects of constraints in order to limit its decision to periods when transmission is adequate to accommodate the request. TAPS argues that information about constraints gained as a result of an initial designation request is of minimal value since a reframed request would take a later place in the queue.

122. TAPS also argues that the clarification provided in Order 890-A that excess capacity created by transmission upgrades should be allocated first to conditional firm customers based on their initial order in the queue further degrades the benefit of network service. Even if network customers could predict periods for which to request secondary network service and firm designations, TAPS argues that they still could not create a service comparable to conditional firm service given the potential benefit of being firmed up by excess capacity produced by later upgrades. TAPS contends that the exclusion of network customers is discriminatory given the Commission's finding that transmission providers provide conditional service to themselves and the requirement under section 28.2 of the

pro forma

OATT that transmission providers “designate resources and loads in the same manner as any Network Customer under Part III of this Tariff.” TAPS further asserts that the Commission should clarify whether the customer supporting the upgrade is protected from having its upgrade sized to meet the needs of earlier-queued conditional firm customers.

Commission Determination

123. The Commission again affirms the decision not to create a conditional firm network service.

77

As the Commission explained in Order No. 890-A, the flexibility to use designated network resources and secondary network service to access undesignated resources already provides a service that is like conditional firm service that can be used to integrate new resources. The Commission also revised section 32.3 of the

pro forma

OATT to make clear that network customers have the right to request the study of special protection schemes like those used by transmission providers in designating resources for their native loads.

78

Further, Order No. 890 provided that network customers may designate off-system resources supported by conditional firm point-to-point service.

79

All of these provisions collectively allow network customers to designate resources in the same manner that transmission providers designate resources for their loads. We therefore reject arguments that denial of conditional firm network service results in network service that is inferior to the transmission provider's own use of the system to serve its load.

77

Order No. 890-A at P 558.

78

Id.

P 559.

79

Order No. 890 at P 1091.

124. While we agree with NRECA that conditional firm customers will be able to request service in advance of secondary network customers, we find this provides no reason to create a new conditional firm service for network customers. Those seeking conditional firm service should have the ability to request service ahead of secondary network service, a non-firm service. Network customers seeking to designate their resources and avoid the use of secondary network service may request the study of special protection schemes in their system impact study. Taken together, the rights of network customers are therefore not inferior to those of conditional firm customers. Indeed, network customers enjoy advantages over conditional firm customers, including access to reliability redispatch to avoid curtailment of their loads. In any event, we remind NRECA and TAPS that network service and point-to-point service were not designed to be identical and the rights and obligations of each type of customer need not be the same.

80

Comparability does not require the same service be made available to network customers and point-to-point customers; rather, the concept applies to the service taken for transmission provider's load by the transmission provider as compared to the service for network customer loads.

80

Order No. 890-A at P 559.

125. Additionally, we disagree with the conclusions that NRECA draws from its hypothetical scenario involving a network customer using secondary network service, a conditional firm customer, and the transmission provider taking power from the same generator. NRECA's assertion that the transmission provider will not curtail its own deliveries from the resource incorrectly assumes that the transmission provider will employ redispatch instead of something akin to conditional firm service. If the transmission provider is

designating network resources using service analogous to conditional firm service, it will use a special protection scheme to curtail or limit the transmission service for the resource at the same time a network customer's secondary network service is curtailed. The conditional firm customer also should be curtailed about the same amount as the secondary network service customer because the conditional firm service, by definition, should be subject to curtailment at the secondary network service level during the forecast constraints.

81

NRECA's objection to conditional firm service is therefore based on a misunderstanding of the new service and the way that transmission providers use similar mechanisms to designate resources on their systems.

81

We note, however, that network customer load is unlikely to be curtailed due to provision of reliability redispatch. In contrast, conditional firm customers' transactions are more likely to be curtailed during conditional periods because reliability redispatch is not required for point-to-point service.

126. In Order No. 890-A, the Commission clarified that customers supporting upgrades have priority access to the capability created by those upgrades even if conditional firm customers earlier in the queue opt not to support upgrades.

82

The Commission also stated 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.”

83

TAPS requests clarification of the former determination and objects to the latter determination. We clarify that customers supporting upgrades, whether through direct assignment or rolled-in pricing, will not have their upgrades sized based on the needs of planning redispatch and conditional firm customers that opt not to support upgrades. Upon further consideration, we grant rehearing of Order No. 890-A with regard to how excess capacity created by upgrades should be allocated among transmission customers.

84

We conclude that it is premature to make this determination given that the complicated series of events leading to such an allocation may never come to pass.

85

Should transmission providers encounter this series of events, they should file, prior to completion of the transmission upgrades, proposed tariff provisions to address the allocation of the transmission capacity.

82

Order No. 890-A at P 584.

83

Id.

84

We note that the clarification provided in Order No. 890-A with regard to the allocation of excess capacity was not required to address the original issue raised by Southern.

See id.

P 571, 584.

85

For this circumstance to present itself, all of the following, at a minimum, must occur: (1) Conditional firm or planning redispatch service is granted to a customer unwilling to support upgrades; (2) a customer seeking service over the same transmission capacity agrees to support transmission upgrades to secure its service; (3) the upgrade construction is completed; (4) the upgrades create additional capacity that the customer supporting the upgrades did not request; and (5) the conditional firm or planning redispatch customer will be taking service when construction is completed.

b. Implementation of Planning Redispatch and Conditional Firm Service

(1) Characteristics of Service

127. The Commission reiterated in Order No. 890-A that both the transmission provider and reliability coordinator play a role in ensuring that adequate reliability is maintained when a customer uses third-party provided reliability dispatch. The Commission stated that this would entail review of redispatch plans submitted by the customers, coordination between the transmission provider and reliability coordinator, and signaling third-party generators when the redispatch is needed. It is the customer's ultimate responsibility, however, to ensure that any technical arrangements required by the reliability coordinator are in place in order to maintain reliability.

128. With regard to the conditional firm option, the Commission reiterated that transmission providers are allowed to add a risk factor to their calculation of annual curtailment hours to account for forecasting risks. The Commission clarified that the modeling of conditions to determine the number of non-firm curtailments for any conditional firm request should not incorporate unexpected events, such as hurricanes and ice storms.

Requests for Rehearing and Clarification

129. E.ON U.S. requests that the Commission clarify that the reliability coordinator oversees third-party-provided planning redispatch to ensure there is no conflict with reliability redispatch. E.ON U.S. also states, however, that third-party planning redispatch may have a negative impact on system reliability and ATC and, therefore, the transmission provider should not be completely separated from the third-party planning redispatch process. E.ON U.S. nonetheless argues that the reliability coordinator is in the best position to monitor the reliability impacts of third-party planning redispatch. E.ON U.S. notes that the reliability coordinator and transmission provider sometimes are separate entities, as in E.ON U.S.'s case where Tennessee Valley Authority is the reliability coordinator.

130. E.ON U.S. asks for further clarification that unexpected events that are not incorporated into the calculation of annual curtailment hours for a conditional firm customer do not impact the number of hours the customer can be curtailed. Although the Commission acknowledged in Order No. 890-A the need for flexibility in modeling various conditions, E.ON U.S. notes the Commission did not specify a level of appropriate risk factor to apply when making annual curtailment calculations and further found that unexpected events should not be included in calculating annual curtailment analysis.

86

E.ON U.S. requests that the Commission clarify whether unexpected events that are not included in the curtailment hours calculation also do not count towards the annual curtailment hours for customers taking conditional firm service.

86

Citing

Order No. 890-A at P 588.

Commission Determination

131. In Order No. 890, the Commission directed transmission providers to modify their OASIS sites to allow for posting of third-party offers for planning redispatch and to work with NAESB to develop the OASIS functionality and any necessary business practice standards to allow for third-party planning redispatch.

87

The Commission noted that provision of third-party planning redispatch required coordination between the customer, transmission provider and reliability coordinator, but determined that the customer bears the burden to ensure that the necessary contractual and technical arrangements are in place to maintain reliability.

87

Order No. 890 at P 1007.

132. We clarify in response to E.ON U.S. that the role of the reliability coordinator in coordinating third-party planning redispatch is very limited. The transmission provider should have primary responsibility for overseeing the coordination of third-party planning redispatch. For example, if third-party planning redispatch impacts ATC, as E.ON U.S. suggests, the transmission provider will make this determination and relay that information to the customer. It is important to distinguish reliability redispatch, for which reliability coordinators generally play a larger role, from planning redispatch. Planning redispatch is used to create additional transmission capacity in order to accommodate a request for

long-term firm transmission service.

88

The transmission provider or third-party generation operator must plan to dispatch its generator(s) so that the requested transmission service, otherwise shown unavailable by the transmission provider's ATC model, may be granted. In comparison, reliability redispatch is used to relieve actual system constraints that would otherwise cause curtailment of network customer or transmission provider loads. While the reliability coordinator has a larger role to play in reliability redispatch, its role in coordinating third-party provision of planning redispatch is very limited.

88

See

Order No. 890-A at P 603.

133. With regard to our determination that unexpected events should not be incorporated into the analysis to determine the number of annual curtailment hours applying in any transmission service agreement, we clarify that whether such events impact the accounting for annual curtailment hours depends on the curtailment priority of the service at the time of the event. If an unexpected event occurs when the conditional firm customer is curtailed pursuant to a firm curtailment priority, then the curtailment will not count against the annual hours. In determining whether the annual conditional curtailments are met, transmission providers should count curtailments made when the service is otherwise conditional,

i.e.

, tagged with a secondary network curtailment priority, regardless of whether the curtailment occurred during an unexpected event.

(2) Pricing of Planning Redispatch

134. The Commission affirmed the determination in Order No. 890 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. The Commission clarified that, in months in which generation-related payments are collected for planning redispatch, these payments should be treated as a revenue credit to offset the native load customers' fuel adjustment clause. In months in which the embedded cost rate of transmission is collected for planning redispatch, those revenues should be included in the numerator of the rate calculation as a revenue credit. The Commission stated that transmission providers 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 single rate case filing.

Requests for Rehearing and Clarification

135. E.ON U.S. and EEI request rehearing of the Commission's pricing provisions with respect to the crediting of transmission revenues from planning redispatch. Both repeat arguments that the Commission has forced transmission providers' native load to bear the cost of planning redispatch on behalf of point-to-point customers. They ask the Commission to grant rehearing to require that, when transmission revenues exceed the cost of planning redispatch on a monthly basis, only the amount of the excess transmission revenues should be credited against the cost of transmission service and the remainder should be credited against the fuel adjustment clause. In the alternative, EEI asks the Commission to clarify that, when the transmission revenues exceed the cost of redispatch, all of the revenues should be included as a credit in developing the transmission cost of service that is used to determine the transmission rate, and the generation redispatch costs should be included as a debit in determining the transmission cost of service and also should be credited against the fuel adjustment clause.

136. Southern repeats arguments made on rehearing of Order No. 890 that transmission providers should be able to charge planning redispatch customers the embedded costs of transmission as well as the generation-related costs of providing redispatch. Southern contends that it is unduly discriminatory and arbitrary and capricious to allow a transmission customer to be charged both the costs of generation redispatch and the embedded transmission rate when the redispatch is provided by a third party, but not when redispatch is provided by the transmission provider. In months in which redispatch costs are higher than the embedded cost rate, Southern contends that the transmission provider is similarly situated to a third party generator that provides redispatch because neither would receive transmission revenues for the additional transmission capability created by their redispatch. Southern therefore argues that the policy against “and pricing” is unduly discriminatory as applied to transmission providers and that this disparate treatment of transmission providers and third-party providers of planning redispatch does not withstand scrutiny.

137. Southern also repeats arguments that the Commission incorrectly concluded in Order No. 890-A that planning redispatch creates additional transmission capacity and does not take away firm service from native load and network customers. Southern contends that planning redispatch merely reallocates, rather than creates, transmission capability by forcing certain generators to run and others not to run, thereby changing power flows. Southern, raising a new argument, asserts that the provision of planning redispatch could result in reduced subsequent, later-queued sales of long-term or short-term transmission service that might have produced higher transmission revenues than the provision of planning redispatch. Southern adds that planning redispatch could prevent a network customer from designating a new network resource by taking all of the transmission capacity near a generating source. Southern therefore contends that the Commission's conclusion in Order No. 890-A that the provision of planning redispatch provides purely incremental service without effect to existing transmission capacity is arbitrary and capricious.

Commission Determination

138. The Commission grants clarification regarding the rate treatment of generation-related revenues and revenues from the embedded cost rate of transmission associated with planning redispatch. In Order No. 888, the Commission concluded 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.

89

This rate treatment is appropriate for all generation-related incremental costs, whether the customer pays the embedded cost transmission rate or the costs of planning redispatch in any particular month. Therefore, we direct that in months in which the embedded cost transmission rate is higher than the generation-related costs of providing redispatch, the revenues in excess of the generation-related costs should be credited against the costs of transmission service and the remaining revenues, those representing the monthly costs of reconfiguring generation resources, should be credited against the fuel adjustment clause.

89

See

Order No. 888 at 31,740.

139. We affirm our decision in Order No. 890-A to deny requests to depart

from our long-standing prohibition of “and” pricing for planning redispatch service first adopted in Order No. 888 and followed in Order No. 890.

90

In Order No. 890, the Commission modified pre-existing planning redispatch obligations and lessened the impact on transmission providers (and their customers) with the continuing support of many transmission providers, including Southern. The Commission also modified pricing provisions to allow for the comparison of monthly generation-related costs of planning redispatch to determine the applicable rate. In directing this monthly comparison, the Commission rejected the former provisions for basing the charge on a life of the contract comparison, concluding that it was appropriate to make planning redispatch service more attractive for transmission providers to provide.

91

90

See

Order No. 890 at P 1028.

91

Order No. 890 at P 1025.

140. We also affirm, as the Commission did in Order Nos. 890 and 890-A, the determination in Order No. 888 that planning redispatch creates additional transmission capability.

92

We agree with Southern that provision of planning redispatch may have an impact on subsequent, later-queued requests to use the transmission grid. It is the nature of networked transmission grids that granting any firm point-to-point or network service will impact the ability of those seeking to use the system in the future. The impact of planning redispatch, or any other firm service, on subsequent uses of the grid does not provide a valid reason for lifting the long-standing prohibition on “and” pricing, nor does it undermine the determination in Order No. 888-A that planning redispatch creates additional transmission capacity. To the extent that Southern argues it could collect additional revenues from network customers' designation of additional resources were Southern not providing planning redispatch, we find this unconvincing as network customers are charged for service based on their load not the number of resources designated.

92

Order No. 888-A at 30,267; Order No. 890 at P 1028; Order No. 890-A at P 602, n.241.

2. Rollover Rights

141. In Order No. 890-A, the Commission affirmed the decision in Order No. 890 to limit rollover rights to contracts with a minimum term of five years. The Commission rejected requests to condition application of the minimum five-year term on a demonstration that the relevant generation markets support five-year power supply contracts. The Commission explained that the purpose of its reform of the rollover policy 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. The Commission noted that a point-to-point customer does not need to have a five-year power contract in order to secure a five-year transmission service contract and that the length of the network customer's service agreement, not the length of the power contract supporting a network resource designation, determines whether a customer is eligible for rollover.

142. The Commission also affirmed the decision in Order No. 890 not to eliminate the requirement to match competing requests in order to retain rollover rights. With regard to the effectiveness of the rollover reforms, the Commission acknowledged that requiring a five-year contract term for pending transmission service requests could cause significant disruption to those transmission customers already in the transmission queue at the time of the effective date of Order No. 890. The Commission therefore revised 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).

Requests for Rehearing and Clarification

143. Entergy objects to the Commission's statement in Order No. 890-A that the term of the network customer's underlying service agreement establishes whether a network service reservation is eligible for rollover rights, rather than the term of the relevant designated network resources.

93

Entergy argues that this determination is an unexplained departure from existing rollover policy providing that a network service reservation's eligibility for a rollover is based on the term of the underlying network resource.

94

Entergy argues that network customers most often execute long-term service agreements, sometimes up to as many as 30 years in length, that act as umbrella agreements under which network customers designate and undesignate different network resources as needed to serve network load. Entergy explains that the transmission provider studies these reservations as they are submitted and, if they are deliverable to the relevant network load on a firm basis, then they are designated as network resources.

93

Citing

Order No. 890-A at P 645.

94

Citing Wis. Pub. Power, Inc.

v.

Wis. Pub. Serv. Corp.,

84 FERC ¶ 61,120, at 61,659 (1998) (

WPPI

).

144. Entergy argues that granting rollover rights based solely on the term of a network service agreement, rather than the term of the network resource designation, would effectively ignore the firm deliverability requirement underlying all network resources, allowing a network customer to execute a multi-year service agreement and obtain rollover rights even though it actually may have only designated network resources for as little as one day. Entergy contends that this is not the intent of allowing transmission customers to designate network resources on a short-term basis and constitutes bad transmission policy and undermines reliability.

145. Cargill objects to the revision of section 2.2 of the

pro forma

OATT requiring existing customers to match the longest-term competing request in order to rollover service. Cargill contends that the Commission in Order No. 890 determined that a rollover customer must agree to another five-year contract term or match any longer-term competing request in order to be eligible for a subsequent rollover,

95

but imposed no similar requirement when exercising a rollover right when a subsequent rollover is not desired. Cargill argues that the new requirement to match the longest-term competing request in order to roll over service violates the first-come, first-served principles affirmed in Order No. 890. Cargill suggests, for example, that one potential customer could submit a competing request well in advance of the incumbent's rollover, followed by a second longer-term competing request submitted by another potential customer closer in time to the incumbent's rollover. Cargill contends that the revision to section 2.2 would allow the second customer to effectively preempt the earlier submitted competing request simply because both are vying for capacity subject to the incumbent's rollover right.

95

Citing

Order No. 890 at P 1231.

146. Cargill argues that the revised language of section 2.2 therefore violates the first-come, first-served principle of section 13.2 of the

pro forma

OATT and Commission precedent regarding the application of rollover rights,

96

nullifying the benefit of being the first competitor to submit a competing

request for capacity subject to a rollover right. Cargill contends that the Commission provided no justification in Order No. 890-A for revising its rollover policy to require a customer to match the longest-term competing request in order to rollover its service. Cargill also argues that the Commission provided no notice or opportunity to comment on this change in Commission policy.

96

Citing Tenaska Power Services Co.

v.

Midwest ISO,

106 FERC ¶ 61,230 at P 28,

reh'g denied,

107 FERC ¶ 61,308 (2004) (

Tenaska

).

147. TranServ requests clarification of the Commission's determination regarding the application of the new rollover policies to customer requests queued prior to the effective date of the reforms adopted in Order 890. TranServ states that there is continued confusion over exactly when customers would be required to request long-term service for five years or longer to be granted rollover rights. TranServ contends that customers submitting long-term service requests after July 13, 2007, but prior to the effectiveness of revised section 2.2 of the OATT, are not granted the right to rollover service under the previous one-year term rollover policy. TranServ suggests that it may be more appropriate to allow transmission customers that submitted requests for one year or longer after July 13, 2007, but executed a service agreement prior to the effective date of the revised section 2.2, to also be allowed to operate under the one-year term rollover policy through their first rollover date.

Commission Determination

148. The Commission affirms the determination in Order No. 890-A that the length of a network customer's network service agreement, not the length of a power contract supporting a network service agreement, determines whether the network customer is eligible for rollover rights.

97

A network customer's eligibility for rollover rights is distinct from its ability to rollover a particular resource designation. In order for a network customer to qualify for rollover rights, it must have a network service agreement that satisfies the minimum term necessary for rollover rights. The network customer may then continue to designate and undesignate resources pursuant to that service agreement, subject to the availability of adequate transmission capability to accommodate the request.

97

See

Order No. 890-A at P 645.

149. This does not, as Entergy argues, depart from Commission precedent regarding the network customer's eligibility for rollover rights. At issue in

WPPI

was whether a network customer is required to compete with other firm uses of the system in order to continue its resource designation at the time of rollover.

98

In considering that issue, the Commission first addressed whether rollover rights are available to network customers, concluding that all network customers of the transmission system are long-term users of the system and, therefore, meet the minimum term required to qualify for rollover rights. That determination was appropriate when the one-year contract commitment was in effect, since network service agreements are not short-term in nature. However, when the Commission extended the minimum contract commitment for rollover rights from one year to five years, it was necessary to state more clearly that a network customer's threshold eligibility for rollover rights is linked to the term of its network service agreement.

98

See WPPI,

84 FERC at 61,659.

150. We disagree that this determination undermines the ability of the transmission provider to study the potential impact that future resource designations may have on the system. Although a network customer rolling over its network service may match a competing point-to-point request by extending its network service agreement rather than the power contract supporting the resource designation, the Commission specifically noted that 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.

99

The transmission provider will therefore continue to be able to consider the deliverability of a particular resource at the time of designation. We note that this does not relieve the transmission provider of its obligation under section 28.2 of the

pro forma

OATT to plan, construct, operate and maintain its transmission system in order to provide the network customer with network service over the transmission system.

99

See

Order No. 890-A at P 666, n.264. With regard to competing network resource designations, the Commission affirmed in Order No. 890-A that the network customer seeking rollover must match the term of the competing network resource power contract, consistent with

WPPI

.

See

Order No. 890-A at P 666.

151. We agree with Cargill, however, that the revisions to the language of section 2.2 of the

pro forma

OATT adopted in Order No. 890-A do not properly reflect the obligation of customers rolling over their service to match competing requests for service. Section 2.2 of the Order No. 888

pro forma

OATT required customers rolling over their service to accept a contract term for their new service at least as long as that offered by another potential customer.

100

This obligation was independent of the separate requirement for the rollover customer to request a term of at least one year in order to be eligible for rollover rights on the new service. In amending section 2.2 in Order No. 890, the Commission inadvertently misstated the matching requirement as requiring the customer to match the longer of the term of a competing request or five years in order to roll over its service.

101

That was incorrect, as the requirement to commit to at least five years of service is relevant only to whether the new service has rollover rights, not to whether the customer may roll over its existing service.

100

See

Order No. 888 at 31,665.

101

See

Order No. 890 at Appendix C,

pro forma

OATT section 2.2.

152. The Commission corrected this misstatement in Order No. 890-A by amending section 2.2 to require customers rolling over the service to match the longest competing request.

102

As Cargill points out, the Commission's reference to the longest-term competing request could require a rollover customer taking long-term service to match the length of any competing long-term request. Under the Commission's existing precedent regarding section 2.2 of the

pro forma

OATT, however, there would be only one potential competitor for rollover customers seeking long-term service,

i.e.

, the first customer in the queue requesting competing service.

103

We did not intend to modify this policy and, therefore, revise the language of section 2.2 to require customers rolling over their service to accept a contract term at least equal to a competing request. Any such competing request should be identified by the transmission provider consistent with the reservation priorities stated in the

pro forma

OATT.

102

See

Order No. 890-A at P 695 (“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.”).

103

See Tenaska,

106 FERC ¶ 61,230 at P 48;

see also Cargill Power Marketers, LLC

v.

Southwest Power Pool, Inc.,

122 FERC ¶ 61,068 (2008) (distinguishing the “equal to a competing request” language of section 2.2 of the

pro forma

OATT from the “longest confirmed competing request” language of SPP's tariff).

153. We affirm the decision in Order No. 890-A to continue to apply the current one-year contract commitment requirement to all transmission service requests that were in the transmission provider's transmission queue as of the effective date of the reforms adopted in Order No. 890,

i.e.

, July 13, 2007.

104

This does not mean, as TranServ implies, that the five-year contract

commitment requirement applies to a customer executing a service agreement after that date, but prior to the effectiveness of rollover reforms for the particular transmission provider. The Commission reiterated in Order No. 890-A 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.

105

We therefore agree with TranServ that the one-year contract commitment requirement continues to apply to any customer executing a service agreement prior to the effective date of the transmission provider's revised section 2.2, regardless of when the customer's service request was submitted.

104

See

Order No. 890-A at P 691.

105

See id.

P 684.

154. Finally, we take this opportunity to clarify the statement in Order No. 890-A that the transmission provider may file the revised rollover language only after the transmission provider's Attachment K planning process is accepted by the Commission.

106

Transmission providers may file the revised rollover language adopted in this proceeding at any point after the Commission has accepted the transmission provider's Attachment K compliance filing, even if such acceptance is subject to further compliance obligations, unless otherwise provided by the Commission in the order addressing the Attachment K compliance filing. The effective date of that revised tariff language should be commensurate with the date of the filing containing the revised language.

106

See id.

3. Acquisition of Transmission Service

a. Reservation Priority

155. The Commission confirmed in Order No. 890-A 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. Order No. 890-A also affirmed the decision to limit priority for pre-confirmation status to short-term firm and long-term non-firm requests for service. The Commission also revised sections 1.39, 17.2 and 18.2 of the

pro forma

OATT to make clear that pre-confirmation service should be available to all eligible customers seeking short-term firm and non-firm transmission services.

Requests for Rehearing and Clarification

156. Schedule 20A Service Providers request rehearing of the Commission's decision to revise the

pro forma

OATT to allow pre-confirmation by eligible customers that have not yet executed service agreements. They argue that this revision is inconsistent with how service is reserved on the Phase I/II HVDC-TR transmission system operated by ISO New England and Hydro-Quebec TransEnergie. The Schedule 20A Service Providers state that they have therefore requested approval of a variation from the

pro forma

OATT in their October 11, 2007 compliance filing to accommodate their reservation practices.

157. The Schedule 20A Service Providers also argue more generally that OASIS is not set up to take pre-confirmed applications and, therefore, there is no means by which an eligible customer that is not yet a transmission customer can request pre-confirmed service. They argue that limiting pre-confirmation status to transmission customers does not preclude new customers from seeking service on an equal footing since the obligation to execute a service agreement does not impose an undue burden. To the contrary, they argue that substantial implementation difficulties would arise if transmission providers are forced to recognize pre-confirmation status for eligible customers that do not have access to OASIS. The Schedule 20A Service Providers therefore ask the Commission to grant rehearing to provide that the modifications to sections 1.39, 17.2 and 18.2 of the

pro forma

changes are not necessary or appropri

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