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DEPARTMENT OF ENERGY

U.S. Citizenship and Immigration Services

CFR Citation: 18 CFR Part 37

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

NOTICE: Part II

DOCUMENT ACTION: Order on rehearing and clarification.

SUBJECT CATEGORY: Preventing Undue Discrimination and Preference in Transmission Service

DATES: Effective Date: This rule will become effective September 8, 2008.

DOCUMENT SUMMARY: The Federal Energy Regulatory Commission affirms its basic determinations in Order Nos. 890 and 890A, granting rehearing and clarification regarding certain revisions to its regulations and the pro forma openaccess 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.

SUMMARY: Energy Department, Federal Energy Regulatory Commission,

DOCUMENT BODY 2: Issued June 23, 2008.

SUPPLEMENTAL 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. NonRate Terms and Conditions....................... 116 1. Modifications to LongTerm Firm PointtoPoint 116 Service........................................... 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. 890A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261 (2007) (Order No. 890A).
\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. 888A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 31,048 (1997), order on reh'g, Order No. 888B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888C, 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. 890A, 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
[[Page 39093]]
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 nontransmission
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 longterm firm pointtopoint customers and adopted modifications to other services. Instead of denying a longterm request for pointtopoint 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. 890A.\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. 890A, 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 ongoing 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 nonrate 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 nonrate 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. 890A, 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 ATCrelated reforms adopted by the Commission. A number of petitioners seek rehearing and/or clarification regarding the Commission's ATCrelated determinations in Order No. 890A, 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 transmissionowning 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 [[Page 39094]]
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. 890A.

12. Entergy requests the Commission to clarify that Order No. 890A 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 pathspecific basis by providing transmission customers a scenario analyzer tool that allows them to instantaneously evaluate transfer capability on a sourcetosink 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 890A. If the Commission intended in Order No. 890A 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 transmissionowning 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 transmissionowning 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. 890A 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. 890A. 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. 890A 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 890A 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 [[Page 39095]]
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. 890A at P 51.

\11\ See Order No. 890A at P 36.

18. We disagree with E.ON U.S. that nonmember transmissionowning utilities within an RTO region are similarly situated to member transmissionowning utilities, which the Commission noted in Order No. 890A 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, nonRTO 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 ComponentsCBM and TRM

19. In Order No. 890A, 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 setaside, i.e., point topoint customers, does not pay a transmission charge that includes the cost of the CBM setaside. 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 reservesharing arrangements, reiterating that TRM is the appropriate category for reservesharing.

Requests for Rehearing and Clarification

20. Southern requests rehearing of the Commission's statement that nonfirm pointtopoint transmission customers only receive an indirect benefit from CBM. Southern contends that under normal conditions without generation deficiencies, nonfirm pointtopoint customers may use CBM setaside 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 nonfirm customers. Southern argues that nonfirm 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 nonfirm customers benefit from CBM will be addressed on a casebycase basis.

21. TDU Systems request clarification of the Commission's statement in Order No. 890A that TRM is the appropriate category for reserve sharing arrangements. TDU Systems request confirmation that, if a transmission provider is using another form of setaside for reserve sharing purposes, such as CBM, the transmission providers' customers are entitled to comparable use of the form of setaside. TDU Systems argue that comparability cannot be achieved where the transmission provider does not offer use of transmission capacity setasides to LSE customers comparable to the use that the transmission provider allows itself.
\12\ See Order No. 890A at P 51.

Commission Determination

22. The Commission affirms the requirement adopted in Order No. 890, and affirmed in Order No. 890A, that transmission providers design their transmission charges so that the class of customers not benefiting from the CBM setaside, i.e., pointtopoint customers, does not pay a transmission charge that includes the cost of the CBM set aside.\13\ We disagree with Southern that nonfirm customers benefit directly from the CBM setaside. The Commission acknowledged in Order No. 890A 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 setaside in the first instance.
\13\ See Order No. 890 at P 263; Order No. 890A at P 86. \14\ See Order No. 890A at P 87.

23. The Commission acknowledged in Order No. 890A that use of capacity set aside for CBM by nonfirm customers may result in revenues that are credited to the transmission provider's cost of service, to the benefit of pointtopoint 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 nonfirm 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. 890A 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. 890A, 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 nonaffiliated 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 casebycase basis if there is customerspecific 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
[[Page 39096]]
public. Duke suggests that only a notice that an affiliate requested a publiclyavailable 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 weatherrelated 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 onetime (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 nonholiday, 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. 890A. 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 thirdparties 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. 890A 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. 890A.\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. 890A 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 890A 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 [[Page 39097]]
made available as required in Order No. 890A.

\23\ See Order No. 890A 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 thirdparties 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. 890A, 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 casebycase 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, 24hour, 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. 890A 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. 890A 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. 890A, 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 offsystem 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 onsystem 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 nonexclusive. Southern similarly requests that Schedules 4 and 9 of the pro forma OATT be revised to use ``e.g.'' instead of ``i.e.''
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Commission Determination

45. The Commission grants rehearing of the definition of incremental cost as described in the preamble of Order No. 890A 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. 890A, 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 customerowned 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 customerowned 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. 890A 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. 890A 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. 890A 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 customerowned facilities than for facilities of the transmission provider.\31\
\29\ Order No. 890A 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. 890A'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 customerowned 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 customerowned 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
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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 nonintegrated and thus provide no benefit to the system.

52. East Texas Cooperatives therefore argue that the Commission's statement in Order No. 890A 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 rolledin rate treatment of the same facilities would vary solely as a result of their ownership, since customerowned 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 customerowned facilities are less integrated than transmission provider facilities. Joined by NRECA and TAPS, East Texas Cooperatives argue that customerowned 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. 890A could be read to apply the more stringent integration standard to customerowned 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. 890A 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. 890A at P 35152.

54. Florida Power also requests clarification of language in paragraph 353 of Order No. 890A. 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 customerowned 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 customerowned 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 customerowned 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 customerowned 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 customerowned 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 customerowned 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 nondiscretionary 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. 890A 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 rolledin 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 customerowned 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 61,54445 (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. 890A 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
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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. 890A 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. 890A will not be applied to deny or weaken the comparability requirement for facilities at issue in Docket No. ER93465000, et al. FMPA also asks the Commission to clarify that the transmission credit policy articulated in Order No. 890 and Order No. 890A 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. 061285 (D.C. Cir. filed July 26, 2006).

Commission Determination

60. The Commission affirms the decision in Order Nos. 890 and 890A 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 customerowned 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. 890A, 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. 890A 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 rolledin 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 rolledin 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. 890A at P 349.
\39\ Compare Utah Power & Light Co., 27 FERC ] 61,258, at 61,48587 (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 customerowned 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 planningrelated reforms implemented in Order No. 890, the Commission determined it is now appropriate to grant the same presumption of integration to new customerowned facilities that are similar in scope and design to those transmission provider facilities that are in rates. Implementation of planningrelated reforms will now ensure that most, if not all, transmission facilities are planned on a coordinated basis.\45\ However, only those new customerowned 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 rolledin rate treatment. Other customerowned 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. 890A 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 customerowned 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 rolledin 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.

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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 customerowned 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 rolledin 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 prov

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) 5026540.
Daniel Hedberg (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 5026243.