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Market-Based Rates For Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities

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Start Preamble Issued June 18, 2009.

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Order on rehearing and clarification.

SUMMARY:

The Federal Energy Regulatory Commission is granting in part and denying in part the requests for rehearing and clarification of its determinations in Order No. 697-B, which granted rehearing and clarification of certain revisions to Commission regulations and to the standards for obtaining and retaining market-based rate authority for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable.

DATES:

Effective Date: This order on rehearing will become effective July 29, 2009.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Michelle Barnaby (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8407.

Paige Bullard (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6462.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph No.
I. Introduction1
II. Background2
III. Discussion8
A. Vertical Market Power8
Other Barriers to Entry8
B. Mitigation23
Start Printed Page 30925
Protecting Mitigated Markets23
C. Implementation Process47
Clarifications on Implementation Process47
IV. Information Collection Statement49
V. Document Availability50
VI. Effective Date53
Regulatory Text
Appendix C to Order No. 697-C: Revised Tariff Language
Appendix D-2 to Order No. 697-C: Revised Regional Review Schedule

Before Commissioners: Jon Wellinghoff, Chairman; Suedeen G. Kelly, Marc Spitzer, and Philip D. Moeller.

Order on Rehearing and Clarification

I. Introduction

1. In this order, the Commission addresses requests for rehearing and clarification of Order No. 697-B. Specifically, the Commission clarifies the requirement that sellers file a notification of change in status when they acquire sites for new generation capacity development.[1] The Commission denies the requests for rehearing of the tariff provision governing mitigated sales at the metered boundary and affirms its determination in Order No. 697-B to revise the mitigated sales tariff provision in order to ensure that a mitigated seller making market-based rate sales at the metered boundary does not sell power into the mitigated market either directly or through its affiliates.[2]

II. Background

2. On June 21, 2007, the Federal Energy Regulatory Commission (Commission) issued Order No. 697,[3] codifying and, in certain respects, revising its standards for obtaining and retaining market-based rates for public utilities. In order to accomplish this, as well as streamline the administration of the market-based rate program, the Commission modified its regulations at 18 CFR part 35, subpart H, governing market-based rate authorization. The Commission explained that there are three major aspects of its market-based regulatory regime: (1) Market power analyses of sellers and associated conditions and filing requirements; (2) market rules imposed on sellers that participate in Regional Transmission Organization (RTO) and Independent System Operator (ISO) organized markets; and (3) ongoing oversight and enforcement activities. Order No. 697 focused on the first of the three features to ensure that market-based rates charged by public utilities are just and reasonable. Order No. 697 became effective on September 18, 2007.

3. The Commission issued an order clarifying four aspects of Order No. 697 on December 14, 2007.[4] Specifically, that order addressed: (1) The effective date for compliance with the requirements of Order No. 697; (2) which entities are required to file updated market power analyses for the Commission's regional review; (3) the data required for horizontal market power analyses; and (4) what constitute “seller-specific terms and conditions” that sellers may list in their market-based rate tariffs in addition to the standard provisions listed in Appendix C to Order No. 697. The Commission also extended the deadline for sellers to file the first set of regional triennial studies that were directed in Order No. 697 from December 2007 to 30 days after the date of issuance of the December 14 Clarification Order.

4. On April 21, 2008, the Commission issued Order No. 697-A,[5] in which it responded to a number of requests for rehearing and clarification of Order No. 697. In most respects, the Commission affirmed the determinations made in Order No. 697 and denied rehearing of the issues raised. However, with respect to several issues, the Commission granted rehearing or provided clarification.

5. On July 17, 2008, the Commission issued an order clarifying certain aspects of Order No. 697-A related to the allocation of simultaneous transmission import capability for purposes of performing the indicative screens.[6] Specifically, that order granted the requests for rehearing with regard to footnote 208 of Order No. 697-A and clarified that in performing the indicative screen analysis, market-based rate sellers may allocate the simultaneous import limit capability on a pro rata basis (after accounting for the seller's firm transmission rights) based on the relative shares of the seller's (and its affiliates') and competing suppliers' uncommitted generation capacity in first-tier markets.[7]

6. On December 19, 2008, the Commission issued Order No. 697-B [8] in which it clarified and affirmed the determinations made in Order No. 697-A. Specifically, the Commission provided clarification regarding the allocation of seasonal and longer transmission reservations. The Commission also clarified that it will require a seller making an affirmative statement as to whether a contractual arrangement transfers control to seek a “letter of concurrence” from other affected parties identifying the degree to which each party controls a facility, and to submit these letters with its filing. The Commission denied the request that it clarify that only sites for which necessary permitting for a generation plant has been completed and/or sites on which construction for a generation plant has begun apply under the definition of “inputs to electric power production” in § 35.36(a)(4) of the Commission's regulations. The Commission also revised the definition of “affiliate” in section 35.36(a)(9) of its regulations to delete the separate definition for exempt wholesale generators. In addition, the Commission provided a number of other clarifications with regard to, among others, the pricing of sales of non-power goods and services and the tariff provision governing sales at the metered boundary.

7. On January 28, 2009, in response to Tampa Electric Company's (Tampa Electric) request for extension of time to comply with the tariff provision on Start Printed Page 30926mitigated sales at the metered boundary as revised in Order No. 697-B, the Commission issued an order granting the extension requested by Tampa Electric until such time as the Commission issues an order on rehearing of Order No. 697-B.[9] That order clarified that affected entities must continue to comply with the mitigated sales tariff provision adopted in Order No. 697-A [10] (which became effective on June 6, 2008), until such time as the Commission acts on the requests for rehearing of Order No. 697-B.

III. Discussion

A. Vertical Market Power

Other Barriers to Entry

Background

8. Order No. 697 adopted the NOPR proposal to consider a seller's ability to erect other barriers to entry as part of the vertical market power analysis, but modified the requirements when addressing other barriers to entry.[11] It also provided clarification regarding the information that a seller must provide with respect to other barriers to entry (including which inputs to electric power production the Commission will consider as other barriers to entry) and modified the proposed regulatory text in that regard.[12]

9. On rehearing, the Commission clarified that it was not its intent for the term “inputs to electric power production” to encompass every instance of a seller entering into a coal supply contract with a coal vendor in the ordinary course of business. The Commission clarified that Order No. 697 encompasses physical coal sources and ownership of or control over who may access transportation of coal via barges and railcar trains.[13] Thus, the Commission revised its definition of “inputs to electric power production” in § 35.36(a)(4) as follows: “intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for new generation capacity development; physical coal supply sources and ownership of or control over who may access transportation of coal supplies.” [14]

10. In Order No. 697-B, the Commission rejected the Electric Power Supply Association's (EPSA) proposal that the term “sites for new generation capacity development” mean only sites with respect to which permits for new generation have been obtained or where construction of new generation is underway, and not encompass land that could potentially be used for generation. The Commission explained that “sites for new generation capacity development” should be construed to include ownership of land that could potentially be used for generation, not just sites for which permits for new generation have been obtained or where construction of new generation is underway. The Commission also clarified that “sites for new generation capacity development” does not include land that cannot be used for generation capacity development.[15]

Requests for Rehearing

11. American Wind Energy Association (American Wind) requests rehearing of Order No. 697-B's clarification that sites for new generation capacity development should be construed to include ownership of land that could potentially be used for generation, arguing that the scope and intent behind this requirement was not fully illuminated until the Commission's clarification of this requirement in Order No. 697-B.[16] American Wind contends that the Commission should grant rehearing of the term “sites for new generation capacity development” so as to only require reporting for sites for new generation development that are located in load pockets where a “potential” for vertical market power may exist, and should clarify that it will rely on the existing rebuttable presumption that all other sites do not create a barrier to entry.[17]

12. American Wind argues that the Commission's interpretation of the reporting burden to include sites that could potentially be used for generation substantially increases the regulatory compliance burden on market-based rate sellers, and that the increased burden can be illustrated with respect to the impact on wind energy developers. It explains that in developing new wind power generation sites, wind energy developers seek to initially lease approximately 150 acres for each turbine. American Wind states that in developing a 100 megawatt project using 1.5 megawatt wind turbines, a developer may seek to initially have 10,000 acres of land under control. It further explains that control over such land may result from leases that would likely be made with multiple landowners over a period of several months, and that in regions with significant wind development, it would not be surprising to find a vast number of acres for potential new generation sites under some form of control, via leases or some other form of agreement, by wind energy developers.[18]

13. According to American Wind, the requirement to file notifications of change in status every time a market-based rate seller or its affiliates acquire sites that potentially could be used for generation would create a substantial burden and a competitive risk, while not providing any associated benefit to the Commission. American Wind asserts that wind developers in particular would be subjected to increased risk of the disclosure of their proprietary and competitive information because wind developers regularly compete for new land that can be used for wind development projects.[19] It states that in the development process, wind energy developers spend significant time and effort searching for new land that may be appropriate for wind development sites, and that information as to where a wind energy developer is considering the development of new generation projects is highly proprietary and confidential. American Wind contends that even assuming a filing submitted at the Commission includes information “on a summarized, balancing authority area basis, given the small size of some balancing authorities, the public release of such proprietary and confidential information could lead to competitive harm.” [20] American Wind also argues that if a seller's control of potential new generation sites were alleged to create a new barrier to entry, the Commission, either pursuant to a complaint filed by a third party or a Commission-initiated investigation, would have ample authority to take action and challenge the rebuttable presumption that ownership or control over sites for new generation development does not create a barrier to entry.[21]

14. American Wind therefore requests that the Commission grant rehearing of the term “sites for new generation capacity development” so as to only require reporting for sites for new Start Printed Page 30927generation capacity development that are located in load pockets where a “potential” for vertical market power may exist. American Wind argues that for the purposes of this reporting requirement, the Commission could define load pockets as submarkets where the Commission has determined that internal transmission constraints make the market smaller than the balancing authority area, RTO/ISO footprint or RTO/ISO submarket.[22]

15. If the Commission declines to grant its request to only require reporting for sites for new generation development that are located in load pockets where a “potential” for vertical market power may exist, American Wind requests clarification that the Commission will only require reporting for sites for new generation capacity development when “site control” is first required to be demonstrated in the interconnection process.[23] American Wind claims that sites that have not yet been required to demonstrate site control in the interconnection process would not likely be used to enhance a seller's vertical market power, and accordingly, there is no need for the Commission to be notified of such sites prior to when “site control” is required to be demonstrated. American Wind argues that using this milestone as the triggering point for when a seller must notify the Commission of sites for new generation capacity development “would better align the reporting requirement with the underlying vertical market power concerns that are at the heart of the requirement” and “would strike a better balance between the Commission's regulatory concerns and the compliance burden on and competitive risks to market-based rate sellers.” [24]

Commission Determination

16. We will deny American Wind's request for rehearing of the definition of “inputs to electric power production” so that it requires only reporting for sites for new generation capacity development that are located in load pockets where a “potential” for vertical market power may exist. Such a revision to the requirement is too narrowly focused and therefore would not allow the Commission to timely monitor for potential barriers to entry or affiliate abuse involving generation sites. Since load pockets typically exist in areas (e.g., population centers) that are not well-suited for the development of renewable generation sources (e.g., large wind farms requiring thousands of acres of land),[25] limiting the reporting of sites for new generation development to just load pockets would mean that the Commission would not be informed of most instances where land was being acquired for the development of new renewable generation capacity.

17. With respect to American Wind's alternative request that the Commission only require reporting for sites for new generation capacity development when site control is first required to be demonstrated in the interconnection process, we believe this approach has merit, as modified below. Modifications are necessary because it is not clear that American Wind's request would address both its concerns about the disclosure of commercially sensitive information and the Commission's regulatory concerns regarding a seller's ability to erect barriers to entry through its acquisition of sites for new generation capacity development. First, the information provided in an interconnection request, including the demonstration of site control, is not required to be public.[26] Second, transmission providers post the location of interconnection requests on OASIS by county and State, but do not post the identity of the interconnection customer when the interconnection request is made “because disclosing the identity at that early stage may put the Interconnection Customer at a competitive disadvantage and its project at risk.” [27] Thus, the American Wind alternative approach would require the seller to report information that in the interconnection process may be considered non-public and proprietary. While American Wind's concerns about the disclosure of commercially sensitive information could be addressed by allowing sellers to file site information with the Commission confidentially, we do not believe that it is appropriate to routinely permit change in status reports to be filed at the Commission as non-public documents. One of the purposes of the change of status reporting requirement is to provide interested parties the opportunity to intervene and comment if they believe the seller's acquisition of sites for new generation capacity development creates a barrier to entry, which could be undermined if such reports were routinely filed with confidential information redacted.[28]

18. Accordingly, in order to address our regulatory concerns and the concerns of American Wind, we grant rehearing and revise section 35.42 of our regulations to require, for all entities with market-based rate authorization, quarterly reporting of a seller's acquisition of a site or sites for new generation capacity development for which site control has been demonstrated in the interconnection process and for which the potential number of megawatts that are reasonably commercially feasible on the site or sites for new generation capacity development is equal to 100 megawatts or more. For the purposes of this reporting requirement, we will use the definition of “site control” that is provided in section 1 of the Standard Large Generator Interconnection Procedures (LGIP).[29] To the extent that a seller elects to make a monetary deposit so that it may demonstrate site control at a later time in the interconnection process,[30] such deposit will trigger this quarterly reporting requirement instead of the demonstration of site control if the Start Printed Page 30928potential number of megawatts that are reasonably commercially feasible on the site or sites for new generation capacity development is equal to 100 megawatts or more.[31] All market-based rate sellers will be required to report the acquisition of control of sites for new generation capacity development on a quarterly basis instead of within 30 days of the acquisition.[32] Such quarterly filings must be submitted within 30 days after the end of each quarter, e.g., by April 30 for the first quarter. Thus, the time period in which sellers are required to report the acquisition of control of sites for new generation capacity development is being extended, which will ease some of the administrative burden about which American Wind has raised concerns. For all changes in status other than the acquisition of control of sites for new generation capacity development, all sellers will still be required to file a change in status report no later than 30 days after the change in status occurs.[33]

19. The quarterly reports that entities will be submitting to report the acquisition of control of a site or sites for new generation capacity development must include: (a) The number of sites acquired; (b) the relevant geographic market in which the sites are located; [34] and (c) the maximum potential number of megawatts that are reasonably commercially feasible on the sites reported, which must be justified.[35] The information regarding the maximum potential number of megawatts for the sites may be reported on an aggregate basis for each relevant geographic market(s) in which the site(s) are located, i.e., without providing the specific location of particular sites. Sellers must provide a justification for the number of megawatts that they estimate could be developed on the site or sites. Such justification must be based on the maximum potential number of megawatts that could be produced on the site with the technology for which the site was acquired. Sellers must be forthright in estimating and reporting the maximum potential number of megawatts that are reasonably commercially feasible on the site or sites for new generation capacity development. The Commission will use all of this reported information to identify sellers that may be erecting barriers to entry. We will revise section 35.42 of our regulations to reflect this site acquisition change to the change in status reporting requirement.

20. Separate and apart from the above reporting requirement, and in order to address our concern that Sellers may acquire land that is not used for the development of new generation capacity, and that is instead acquired for the purpose of preventing new generation capacity from being developed on that land, a Seller must also report any land it has acquired, taken a leasehold interest in, obtained an option to purchase or lease, or entered into an exclusivity or other arrangement to acquire for the purpose of developing a generation site and for which site control has not yet been demonstrated (as discussed above) during the prior three years (triggering event), and for which the potential number of megawatts that are reasonably commercially feasible on the land for new generation capacity development is equal to 100 megawatts or more. A Seller must report each such triggering event in a single report by January 1 of the year following the calendar year in which the triggering event occurred. Thus, for example, if a Seller acquires land for new generation capacity development in January 2009, and additional land in March 2009 and it has not demonstrated site control for generation projects on that land (as described above) as of January and March 2012, respectively, then such Seller must file a change in status report notifying the Commission of both acquisitions by January 1, 2013. The information that must be provided and the aggregation of the maximum potential number of megawatts by relevant geographic market is the same as required in the quarterly reports, as described above. We will revise section 35.42 of our regulations to reflect this additional change to the change in status reporting requirement.

21. Finally, for acquired, leased or optioned land lacking site control that have already been held for three years or more prior to the effective date of this order, a Seller must report the required information by January 1, 2010, unless this information has been previously provided to the Commission.

22. We believe that our revision to this requirement strikes a balance by addressing American Wind's concern regarding the burden of the existing requirement and its concern that commercially sensitive information about sites for wind generation development will be made public, and by also providing the Commission with the information necessary to evaluate a seller's ability to erect barriers to entry. In particular, permitting the information on sites for new generation capacity development to be provided on an aggregate basis for each relevant geographic market reduces any potential competitive harm that could result from reporting the location of the sites (since reporting will be on an aggregate basis), and also enables the Commission, which evaluates vertical market power by examining the relevant geographic market in which a seller is located, to obtain the information it needs to evaluate a seller's ability to exercise market power in a particular relevant geographic market. Requiring quarterly (and yearly, as necessary) reporting of sites acquired for new generation capacity development also reduces the administrative burden on sellers, which previously were required to report the acquisition of sites within 30 days of the acquisition. In addition, requiring reporting on a quarterly basis (and yearly, as necessary) will likely reduce any potential competitive harm that could result from the disclosure of the nominal information regarding the location of the site or sites for new generation capacity development. Further, in their applications for market-based rate authority and their updated market power analyses, sellers are obligated to make an affirmative statement that they have not erected barriers to entry into the relevant market and will not erect barriers to entry into Start Printed Page 30929the relevant market. This continuing obligation provides assurance to the Commission that a seller is not erecting barriers to entry.[36]

B. Mitigation

Protecting Mitigated Markets

Sales at the Metered Boundary

Background

23. In Order No. 697, the Commission stated that it would continue to apply mitigation to all sales in the balancing authority area in which a seller is found, or presumed, to have market power. However, the Commission said it would allow mitigated sellers to make market-based rate sales at the metered boundary between a balancing authority area in which a seller is found, or presumed, to have market power and a balancing authority area in which the seller has market-based rate authority, under certain circumstances.[37] The Commission also adopted a requirement that mitigated sellers wishing to make market-based rate sales at the metered boundary between a balancing authority area in which the seller was found, or presumed, to have market power and a balancing authority area in which the seller has market-based rate authority maintain sufficient documentation and use a specific tariff provision for such sales.[38]

24. On rehearing in Order No. 697-A, the Commission revised the tariff language governing market-based rate sales at the metered boundary to conform with the discussion in the December 14 Clarification Order regarding use of the term “mitigated market.” The Commission stated that, as explained in the December 14 Clarification Order, “balancing authority area in which a seller is found, or presumed, to have market power” is a more accurate way to describe the area in which a seller is mitigated.[39]

25. In addition, after considering comments regarding the difficulty of determining and documenting intent, the Commission decided in Order No. 697-A to eliminate the intent element of the tariff provision, which stated that “any power sold hereunder is not intended to serve load in the seller's mitigated market.” Because the Commission eliminated the seller's intent requirement, it modified the tariff provision to require that “the mitigated seller and its affiliates do not sell the same power back into the balancing authority area where the seller is mitigated.” [40] In this regard, the Commission noted that “[t]o provide additional regulatory certainty for mitigated sellers, the Commission clarified that once the power has been sold at the metered boundary at market-based rates, the mitigated seller and its affiliates may not sell that same power back into the mitigated balancing authority area, whether at cost-based or market-based rates.” [41] The Commission also stated that because it was eliminating the intent requirement, it need not address issues raised regarding documentation necessary to demonstrate the mitigated seller's intent.

26. Further, in response to a request for clarification submitted by the Pinnacle West Companies (Pinnacle), the Commission also clarified in Order No. 697-A that mitigated sellers and their affiliates are prohibited from selling power at market-based rates in the balancing authority area in which a seller is found, or presumed, to have market power.[42] Accordingly, the Commission clarified that an affiliate of a mitigated seller is prohibited from selling power that was purchased at a market-based rate at the metered boundary back into the balancing authority area in which the seller has been found, or presumed, to have market power. The Commission stated that to the extent that the mitigated seller or its affiliates believe that it is not practical to track such power, they can either choose to make no market-based rate sales at the metered boundary or limit such sales to sales to end users of the power, thereby eliminating the danger that they will violate their tariff by re-selling the power back into a balancing authority in which they are mitigated.[43]

27. In Order No. 697-B, in response to the rehearing request of E.ON U.S. LLC (E.ON), the Commission explained that it appreciated concerns regarding the difficulty of defining the term “same power.” For this reason, the Commission revised the tariff provision for market-based rate sales at the metered boundary, which included revising the provision stating that the “Seller and its affiliates do not sell the same power back into the balancing authority area where the seller is mitigated,” to state that “if the Seller wants to sell at the metered boundary of a mitigated balancing authority area at market-based rates, then neither it nor its affiliates can sell into that mitigated balancing authority area from the outside.” The Commission noted that this revised tariff language will prevent a mitigated seller making market-based rate sales at the metered boundary from selling power into the mitigated market through its affiliates. It also explained that sellers may choose to make no market-based rate sales at the metered boundary, or to limit such sales to end users of the power, thereby eliminating the danger they will violate their tariff by re-selling power back into a balancing authority in which they are mitigated.[44]

Requests for Rehearing

28. On rehearing of Order No. 697-B, E.ON again takes issue with the mitigated sales tariff provision, arguing that the Commission erred in revising the mitigated sales tariff provision in Order No. 697-B. E.ON contends that the revised tariff provision is overbroad and prohibits legitimate transactions. It argues that the tariff provision should be revised to state that “(ii) if the Seller sells at the metered boundary of a mitigated balancing authority area at market-based rates, then neither it nor its affiliates can sell into that mitigated balancing authority area from the outside at the same border for delivery at the same time except pursuant to long-term (one-year or longer) agreements or as a result of changed circumstances.” [45] E.ON argues that, as revised in Order No. 697-B, the tariff provision governing mitigated sales does not expressly state that a border sale need actually occur. E.ON suggests that the Commission should change the words “wants to sell” to “sells” to eliminate any risk of misinterpretation. In support of its proposal, E.ON argues that the mitigated sales tariff provision should contain a “temporal limitation” so that it cannot be read to prohibit a mitigated seller or its affiliates from ever selling from the outside into the mitigated balancing authority area. E.ON believes that the Commission intended only to stop the “looping” of power in a manner that circumvents the mitigation imposed on an entity.[46]

29. E.ON also argues that the mitigated sales tariff provision should contain an exemption for retail or Start Printed Page 30930wholesale cost-based requirements contracts into the mitigated balancing authority area from the outside so that long-term purchases from outside a mitigated market used to serve retail or cost-based wholesale requirements customers do not restrict the ability of a mitigated seller from making a spot “outbound” border sale. According to E.ON, failure to modify the condition in this manner would severely restrict the ability of its public utility subsidiaries Louisville Gas and Electric Company and Kentucky Utilities Company to make truly “outbound” off-system sales at the border of their control area, leading to higher prices.[47] E.ON also proposes adding language to the condition so as to carve out long-term agreements of one-year or more in duration that provide for the sale of power into the mitigated market from the outside. E.ON contends that as revised in Order No. 697-B, the mitigated sales tariff provision could prohibit transactions necessitated by reserve sharing agreements or changed operational circumstances, and could have a chilling effect on forward contracting by forcing mitigated sellers to only transact in real time because of their concerns that they may guess wrong and need to buy power at the last minute if they are short, or sell power at the last minute if called upon under a reserve sharing agreement.[48] In addition, E.ON asserts that the revised mitigated sales tariff provision could prohibit opportunity purchases by utilities that seek to reduce the costs of serving load.[49]

30. Pinnacle, too, seeks further revision to the mitigated sales tariff provision and argues that the Commission erred in linking all market-based rate sales made at the metered boundary to all incoming sales into a mitigated balancing authority area. Pinnacle requests that the Commission clarify that making a border sale does not prohibit all future sales of a mitigated seller or its affiliates from entering the mitigated balancing authority area. It states that, at a minimum, the Commission should clarify that it does not intend for the revised provision to capture cost-based sales into or out of a mitigated balancing authority area.[50] Pinnacle states that if the revised provision is interpreted to prohibit any subsequent sales of a mitigated seller or its affiliates from entering the mitigated balancing authority area, this would completely preclude the mitigated seller from selling into the mitigated balancing authority area. Such a result, Pinnacle contends, could endanger the stability of the Phoenix Valley Load Pocket in the event of an emergency,[51] and could result in Pinnacle violating its must-offer requirements. Specifically, Pinnacle states that if it is not permitted to make sales into the mitigated balancing authority area, or is effectively prohibited from making sales at border points, its posting of available capacity will be less effective for the Southwest in that Pinnacle would have to withhold available generation due to its inability to make sales in certain areas.[52]

31. MidAmerican Energy Company (MidAmerican) and American Electric Power Service Corporation (AEP) also seek rehearing of the mitigated sales tariff provision as revised in Order No. 697-B. These petitioners argue that the Commission erred in adopting an overly broad mitigation provision that could restrict legitimate transactions. They contend that under the tariff provision adopted in Order No. 697-B, mitigated utilities are presented with three alternatives, each of which “unnecessarily and unfairly” disadvantages their customers: (i) Decline to make market-based rate sales and thereby forego revenues used to reduce system costs; (ii) decline to import power from “the outside” and thereby forego least-cost resources that could be used to reliably serve load and make sales within the mitigated market; or (iii) make sales to customers within the mitigated market at prices that may not recover incremental costs, thereby unfairly subsidizing those transactions.[53] MidAmerican and AEP therefore assert that the Commission should rescind Order No. 697-B's revision and revert to the mitigated sales tariff provision adopted in Order No. 697. According to these petitioners, the tariff provision adopted in Order No. 697 captures transactions purposefully structured to evade mitigation while permitting utilities to continue to engage in legitimate transactions from the “outside,” even when energy scheduled under those transactions subsequently is reflected in the price for opportunity sales made within the balancing authority area.[54]

32. MidAmerican and AEP argue that if the Commission declines to grant rehearing, it should clarify that the mitigated sales tariff provision applies only to short-term purchases made from the “outside” by the mitigated seller and not to deliveries scheduled from the mitigated seller's own generation originating “outside” the mitigated balancing authority area or from long-term capacity contracts entered into to meet load requirements. These petitioners contend that these arrangements “do not involve the Commission's ricochet concern and should not be swept within the Order No. 697-B mitigation provision.” [55]

33. Xcel Energy Services Inc. (Xcel) requests clarification that the prohibition on sales into the mitigated balancing authority area does not prevent a mitigated seller from engaging in a purchase of economy power from outside the mitigated balancing authority area in order to lower costs for serving native load. It argues that mitigated sellers that make sales of power at border locations may have opportunities to enter into legitimate economy purchases outside the balancing authority area that would serve to lower overall generation costs to their native load customers. Xcel contends that one mitigation option is to “track the power from a border sale with the possibility of retroactive re-pricing.” [56]

34. Xcel requests clarification that mitigated sellers are only prohibited from making sales into a mitigated balancing authority area if the seller is simultaneously engaged in a sale at the metered boundary.[57] In support of this request, Xcel argues that during periods when the seller is not making sales at the border of its mitigated balancing authority area, there would be no way for the seller or its affiliates to benefit from their market power in the mitigated balancing authority area through a sale that originates outside of that mitigated balancing authority area.[58] Xcel therefore asks for clarification that it is permitted to enter into a sale at a delivery point located outside of the mitigated balancing authority area to a counterparty within the balancing authority area.

35. The Edison Electric Institute (EEI) likewise seeks rehearing of the mitigated sales tariff provision as set forth in Order No. 697-B.[59] EEI contends that Start Printed Page 30931the revised provision will unnecessarily constrain sales by mitigated sellers and their affiliates to the detriment of customers in all markets. EEI argues that as revised in Order No. 697-B, the mitigated sales tariff provision could be interpreted to prohibit all sales by mitigated sellers and their affiliates into a mitigated market from the outside if the sellers opt to engage in one or more metered boundary sales. EEI asserts that this interpretation would completely exclude all sales into the mitigated balancing authority area by a mitigated seller and its affiliates, removing these sellers from the marketplace and exacerbating any potential imbalance of market power in the mitigated balancing authority area.[60] EEI contends that the revised tariff language could be interpreted to violate certain must-offer and load-following requirements.

36. EEI argues that the Commission should return to the intent-based concept adopted in Order No. 697, while also identifying five types of transactions that would be permitted without first needing to demonstrate intent even if a mitigated seller does engage in market-based rate sales at the metered boundary.[61] EEI asserts that the following five types of transactions should be permitted without first needing to demonstrate intent, even if a mitigated seller does engage in market-based rate border sales: (1) Sales at “liquid trading hubs” or into ISO and RTO markets outside of the seller's mitigated market; (2) cost-based sales in which title transfers within the mitigated market (whether they are sourced and sunk in the mitigated market, are sourced “into” the mitigated market from the outside by the seller or its affiliates, or are wheeled “out of” the mitigated market by a purchaser); (3) sales to load-serving entities such as investor-owned utilities, municipalities, and cooperatives that serve retail load outside the mitigated market, even if those entities may at times need to sell power back into the mitigated market if their supply is too great (since the timing and occurrence of such excess-power sales back into the mitigated market will be beyond the control of the mitigated seller); (4) other types of transactions that are independent of the border sales, such as sales of blocks of power to be delivered at dates and times other than the border sale block of power, power made available under must-offer requirements, and load-following power; and (5) to bolster reliability, the Commission should clarify that the border sale constraints do not require a mitigated seller or its affiliates, which otherwise would be precluded from selling power into the mitigated area from the outside, to withhold making those sales during times at which the seller or affiliates are called on to act to maintain system reliability. EEI argues that at a minimum, the Commission should clarify that the border sales constraints will not prevent emergency sales, sales that are required to maintain reserve levels or to comply with system redispatch obligations, or sales that are otherwise authorized by the Commission either generically or case-by-case.[62]

37. EEI also includes an expedited motion for partial stay in its rehearing request in which it asks that the Commission stay the effectiveness of the border sales constraints set forth in Order Nos. 697, 697-A and 697-B until at least 30 days after the Commission has acted on the merits of EEI's request for rehearing.[63]

38. Separately, Tampa Electric submitted a motion for an extension of time to comply with the revised mitigated sales tariff provision set forth in Order No. 697-B. Tampa Electric requests that the Commission defer the effective date of the modified language governing mitigated sales at the metered boundary pending Commission action on requests for rehearing of Order No. 697-B on this issue.[64] Tampa Electric also states that it supports EEI's request for rehearing.

39. On January 27, 2009, the National Rural Electric Cooperative Association (NRECA) and the American Public Power Association (APPA) filed an answer in response to EEI's motion for partial stay. NRECA and APPA argue that EEI's motion for partial stay should be denied because EEI does not demonstrate that a stay is appropriate. They argue that EEI does not specify any irreparable injury that EEI or its member companies will suffer absent a stay, does not address whether the requested stay would substantially harm other parties, and does not show that the stay is in the public interest. They point out that EEI's request for rehearing is the third time in this proceeding that sellers have requested the Commission to modify the restrictions on market-based sale at the metered boundaries of mitigated balancing authority areas.[65] NRECA and APPA also argue that ending all restrictions on market based rate sales at the metered boundary of balancing authority areas in which a seller is mitigated, even temporarily, would harm wholesale markets and customers.[66]

Commission Determination

Procedural Issues

40. We find that EEI does not provide the required justification for a stay of the mitigated sales tariff provision. Under section 705 of the Administrative Procedure Act (APA), the Commission may stay its action when it finds that “justice so requires.” [67] In addressing motions for stay, the Commission considers: (1) Whether the moving party will suffer irreparable injury without a stay; (2) whether issuing a stay will substantially harm other parties; and (3) whether a stay is in the public interest.[68] The Commission's general policy is to refrain from granting a stay of its orders, to assure definiteness and finality in Commission proceedings.[69] The key element in the inquiry is irreparable injury to the moving party.[70] If a party is unable to demonstrate that it will suffer irreparable harm absent a stay, we need not examine the other factors.[71] However, the Commission may examine the other factors where appropriate.[72]

41. EEI's request for stay does not address whether it will suffer irreparable injury without a stay of the mitigated sales tariff provision, and also does not address whether issuing a stay Start Printed Page 30932will substantially harm other parties or whether a stay is in the public interest. Rather, EEI's request for stay consists only of the following statement: “[g]iven the serious, negative potential effects of the border sales related constraints set out in Orders No. 697, 697-A, and 697-B on market participants and customers in mitigated and non-mitigated markets, EEI requests that the Commission stay the effectiveness of those constraints until at least 30 days after the Commission has acted on the merits of EEI's request for rehearing.” [73] This claim is too broad and speculative to justify the granting of injunctive relief.[74] We also note that EEI did not raise issues concerning mitigated sales at the metered boundary on rehearing of Order Nos. 697 and 697-A. Because EEI fails to provide the required justification for a stay of the mitigated sales tariff provision, EEI's motion for a partial stay is denied.[75]

Substantive Issues

42. We deny the requests for rehearing concerning the mitigated sales tariff provision. However, we agree with E.ON that the tariff provision should be revised to state “if the Seller sells” instead of “if the Seller wants to sell * * *.” We clarify that it is not the seller's intent, but rather the seller's action that triggers the limitation set forth in the mitigated sales tariff provision. We affirm our determination to revise the mitigated sales tariff provision in Order No. 697-B in order to ensure that a mitigated seller making market-based rate sales at the metered boundary does not sell power into the mitigated market either directly or through its affiliates. Thus, we will revise the mitigated sales tariff provision to provide that “if the Seller sells at the metered boundary of a mitigated balancing authority area at market-based rates, then neither it nor its affiliates can sell into that mitigated balancing authority area from the outside.” [76] Petitioners' arguments on rehearing of Order No. 697-A indicated that they cannot guarantee that sales at the metered boundary ultimately serve load in a competitive market beyond the balancing authority area where the seller is mitigated.[77] As explained in Order No. 697, “[a]llowing market-based rate sales by a seller that has been found to have market power, or has so conceded, in the very market in which market power is a concern is inconsistent with the Commission's responsibility under the FPA to ensure that rates are just and reasonable and not unduly discriminatory.” [78] Accordingly, mitigated sellers and their affiliates are prohibited from selling power at market-based rates in the balancing authority area in which the seller is found, or presumed, to have market power.[79] Thus, we affirm the Commission's determination to revise the mitigated sales tariff provision in Order No. 697-B in order to ensure that a mitigated seller making market-based rate sales at the metered boundary does not sell power into the mitigated market either directly or through its affiliates. We also reiterate that mitigated sellers may choose to make no market-based rates sales at the metered boundary, or to limit such sales to end users, thereby eliminating the risk that they will re-sell power back to the balancing authority area where they are mitigated.[80]

43. With respect to petitioners' arguments that the mitigated sales tariff provision adopted in Order No. 697-B interferes with must-offer and reliability requirements, reserve sharing agreements, and cost-based requirement contracts, we note that if a mitigated seller does not make market-based rate sales at the border, either that mitigated seller or its affiliates may make sales at cost-based rates into the balancing authority area in which it is mitigated. A mitigated seller can perform each of the above-enumerated functions either by selling at cost-based rates within its restricted balancing authority area, selling at cost-based rates at the metered boundary of its restricted balancing authority area, or by selling at market-based rates at the metered boundary as long as it makes sure that title to the power sold transfers at or beyond the metered boundary. Moreover, we note that our restrictions on sales at the border only apply to new agreements that the seller enters into prospective from the date that Order No. 697-B became effective. No existing agreements are upset or need to be revised in any way provided that the seller abides by our restrictions on any new agreements that it enters into prospectively. Of the rehearing requests that have been filed in this proceeding on this issue, none have identified in this rehearing why it is burdensome or unreasonably costly for sellers to enter into new power sales agreements where title transfers at or beyond the metered boundary between the mitigated and non-mitigated balancing authority areas.[81] Given that many petitioners have acknowledged that the approaches in Order No. 697 and 697-A would be extremely difficult to enforce because even the sellers themselves cannot guarantee that power sold on the seller's side of the metered boundary will not somehow find its way back into the restricted market, we do not believe it is appropriate to return to a rule that is difficult not only for sellers to comply with but also for the Commission to enforce. Such an impracticable rule will not enable the Commission to ensure that market power is not being exercised in the restricted market.

44. With respect to petitioners' requests that the Commission return to the intent-based concept first used in Order No. 697, we note that in Order Start Printed Page 30933No. 697-A, the Commission revised the mitigated sales tariff provision to remove the intent element in response to petitioners' requests, including Pinnacle, who questioned how the Commission could ensure that a mitigated seller knows what an unaffiliated buyer intends to do with power, and complained that it is difficult and administratively burdensome to determine and document intent.[82] In Order No. 697-A, the Commission agreed with petitioners that it would be difficult to determine and document intent, and therefore decided to eliminate the intent element of the tariff provision. On rehearing of Order No. 697-B, petitioners have not provided any new arguments that persuade us that returning to the intent-based concept first used in Order No. 697 will not present the same problems regarding the ability to determine and document intent.

45. In addition, the mitigated sales tariff provision in Appendix C of Order Nos. 697-A and 697-B inadvertently omitted language that was included in the provision adopted in Order No. 697. Accordingly, we will revise the tariff provision for market-based rate sales at the metered boundary as follows (bold font indicates new text):

Sales of energy and capacity are permissible under this tariff in all balancing authority areas where the Seller has been granted market-based rate authority. Sales of energy and capacity under this tariff are also permissible at the metered boundary between the Seller's mitigated balancing authority area and a balancing authority area where the Seller has been granted market-based rate authority provided: (i) Legal title of the power sold transfers at the metered boundary of the balancing authority area where the seller has market-based rate authority; and (ii) if the Seller sells at the metered boundary of a mitigated balancing authority area at market-based rates, then neither it nor its affiliates can sell into that mitigated balancing authority area from the outside. Seller must retain, for a period of five years from the date of the sale, all data and information related to the sale that demonstrates compliance with items (i) and (ii) above.

46. Sellers that have already adopted the tariff language prescribed in Order No. 697-B are directed to revise the provision in accordance with this order on the next occasion when they otherwise would be required to file revised tariff sheets with the Commission, a change in status filing, or triennial review.[83]

C. Implementation Process

Clarifications on Implementation Process

Background

47. In Order No. 697, to ensure greater consistency in the data used to evaluate Category 2 sellers, the Commission modified the timing for the submission of updated market power analyses. Order No. 697 requires analyses to be filed for each seller's region on a pre-determined schedule, rotating by geographic region where two regions are reviewed each year, with the cycle repeating every three years.[84] In Order No. 697-A, the Commission provided additional guidance regarding the implementation process. In particular, it explained that in the December 14 Clarification Order, it clarified that “transmission-owning utilities with market-based rate authority and their affiliates with market-based rate authority are the entities required to file their updated market power analyses first in each region.” [85] Accordingly, in Order No. 697-A, the Commission revised Appendix D to make clear that transmission owners and their affiliates have earlier filing periods than other entities required to file in each region.[86]

48. Upon further review of the Schedule for All Other Entities provided at Appendix D-2 to Order No. 697-A, it has come to our attention that the list of entities required to file updated market power analyses omits the 2010 filing dates for Southwest and Northwest non-transmission owning entities.[87] Accordingly, we will revise Appendix D to add the following:

Appendix D—2

Schedule for All Other Entities

Entities required to fileFiling period (anytime during the month)Study period
Others in Southwest that did not file in December and have not been found to be Category 1 sellersJune 2010Dec. 1, 2009-Nov. 30, 2010.
Others in Northwest that did not file in June and have not been found to be Category 1 sellersDecember 2010Dec. 1, 2009-Nov. 30, 2010.

IV. Information Collection Statement

49. The Office of Management and Budget (OMB) regulations require that OMB approve certain information collection requirements imposed by an agency.[88] The Final Rule's revisions to the information collection requirements for market-based rate sellers were approved under OMB Control No. 1902-0234. While this order clarifies aspects of the existing information collection requirements for the market-based rate program, it does not add to these requirements. Accordingly, a copy of this order will be sent to OMB for informational purposes only.

V. Document Availability

50. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.

51. From FERC's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

52. User assistance is available for eLibrary and the FERC's Web site during Start Printed Page 30934normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) or e-mail at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at public.referenceroom@ferc.gov.

VI. Effective Date

53. Changes adopted in this order on rehearing will become effective July 29, 2009.

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List of Subjects in 18 CFR Part 35

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Nathaniel J. Davis, Sr.,

Deputy Secretary.

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In consideration of the foregoing, the Commission amends part 35 Chapter I, Title 18,

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PART 35—FILING OF RATE SCHEDULES AND TARIFFS

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1. The authority citation for part 35 continues to read as follows:

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Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.

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2. Section 35.42 is revised to read as follows:

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Change in status reporting requirement.

(a) As a condition of obtaining and retaining market-based rate authority, a Seller must timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority. A change in status includes, but is not limited to, the following:

(1) Ownership or control of generation capacity that results in net increases of 100 MW or more, or of inputs to electric power production, or ownership, operation or control of transmission facilities, or

(2) Affiliation with any entity not disclosed in the application for market-based rate authority that owns or controls generation facilities or inputs to electric power production, affiliation with any entity not disclosed in the application for market-based rate authority that owns, operates or controls transmission facilities, or affiliation with any entity that has a franchised service area.

(b) Any change in status subject to paragraph (a) of this section, other than a change in status submitted to report the acquisition of control of a site or sites for new generation capacity development, must be filed no later than 30 days after the change in status occurs. Power sales contracts with future delivery are reportable 30 days after the physical delivery has begun. Failure to timely file a change in status report constitutes a tariff violation.

(c) When submitting a change in status notification regarding a change that impacts the pertinent assets held by a Seller or its affiliates with market-based rate authorization, a Seller must include an appendix of assets in the form provided in Appendix B of this subpart.

(d) A Seller must report on a quarterly basis the acquisition of control of a site or sites for new generation capacity development for which site control has been demonstrated in the interconnection process and for which the potential number of megawatts that are reasonably commercially feasible on the site or sites for new generation capacity development is equal to 100 megawatts or more. If a Seller elects to make a monetary deposit so that it may demonstrate site control at a later time in the interconnection process, the monetary deposit will trigger the quarterly reporting requirement instead of the demonstration of site control. A notification of change in status that is submitted to report the acquisition of control of a site or sites for new generation capacity development must include:

(1) The number of sites acquired;

(2) The relevant geographic market in which the sites are located; and

(3) The maximum potential number of megawatts (MW) that are reasonably commercially feasible on the sites reported.

(e) A Seller must report to the Commission any land it has acquired, taken a leasehold interest in, obtained an option to purchase or lease, or entered into an exclusivity or other arrangement to acquire for new generation capacity development and for which site control has not yet been demonstrated during the prior three years (triggering event), and for which the potential number of megawatts that are reasonably commercially feasible on the land for new generation capacity development is equal to 100 megawatts or more. A Seller must report each such triggering event in a single report by January 1 of the year following the calendar year in which the triggering event occurred. The information that must be provided and the aggregation of the maximum potential number of megawatts by relevant geographic market is the same as required in the quarterly reports, as described in paragraph (d) of this section.

(f) For the purposes of paragraph (d) of this section, “control” shall mean “site control” as it is defined in the Standard Large Generator Interconnection Procedures (LGIP).

Note:

The following appendix will not be published in the Code of Federal Regulations.

Appendix C to Order No. 697-C

* * * * *

Mitigated Sales

Sales of energy and capacity are permissible under this tariff in all balancing authority areas where the Seller has been granted market-based rate authority. Sales of energy and capacity under this tariff are also permissible at the metered boundary between the Seller's mitigated balancing authority area and a balancing authority area where the Seller has been granted market-based rate authority provided: (i) Legal title of the power sold transfers at the metered boundary of the balancing authority area where the seller has market-based rate authority; and (ii) if the Seller sells at the metered boundary of a mitigated balancing authority area at market-based rates, then neither it nor its affiliates can sell into that mitigated balancing authority area from the outside. Seller must retain, for a period of five years from the date of the sale, all data and information related to the sale that demonstrates compliance with items (i) and (ii) above.

* * * * *

Appendix D-2

Schedule for All Other Entities

Entities required to fileFiling period (anytime during the month)Study period
All others in Northeast that did not file in December including all power marketers that sold in the NortheastJune 2008Dec. 1, 2005-Nov. 30, 2006.
Start Printed Page 30935
All others in Southeast that did not file in June including all power marketers that sold in the Southeast and have not already been found to be Category 1 sellersDecember 2008Dec. 1, 2005-Nov. 30, 2006.
All others in Central that did not file in December including all power marketers that sold in the Central and have not already been found to be Category 1 sellersJune 2009Dec. 1, 2006-Nov. 30, 2007.
All others in SPP that did not file in June including all power marketers that sold in SPP and have not already been found to be Category 1 sellersDecember 2009Dec. 1, 2006-Nov. 30, 2007.
Others in Southwest that did not file in December and have not been found to be Category 1 sellersJune 2010Dec. 1, 2009-Nov. 30, 2010.
Others in Northwest that did not file in June and have not been found to be Category 1 sellersDecember 2010Dec. 1, 2009-Nov. 30, 2010.
Others in Northeast that did not file in December and have not been found to be Category 1 sellersJune 2011Dec. 1, 2008-Nov. 30, 2009.
Others in Southeast that did not file in June and have not been found to be Category 1 sellersDecember 2011Dec. 1, 2008-Nov. 30, 2009.
Others in Central that did not file in December and have not been found to be Category 1 sellersJune 2012Dec. 1, 2009-Nov. 30, 2010.
Others in SPP that did not file in June and have not been found to be Category 1 sellersDecember 2012Dec. 1, 2009-Nov. 30, 2010.
Others in Southwest that did not file in December and have not been found to be Category 1 sellersJune 2013Dec. 1, 2010-Nov. 30, 2011.
Others in Northwest that did not file in June and have not been found to be Category 1 sellersDecember 2013Dec. 1, 2010-Nov. 30, 2011.
End Supplemental Information

Footnotes

2.  Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697-B, 73 FR 79,610 (Dec. 30, 2008), FERC Stats. & Regs. ¶ 31,285 (2008).

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3.  Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252 (Order No. 697 or Final Rule), clarified, 121 FERC ¶ 61,260 (2007), order on reh'g, Order No. 697-A, 73 FR 25,832 (May 7, 2008), FERC Stats. & Regs. ¶ 31,268 (2008); clarified, 124 FERC ¶ 61,055 (2008) (July 17 Clarification Order), order on reh'g, Order No. 697-B, 73 FR 79,610 (Dec. 30, 2008), FERC Stats. & Regs. ¶ 31,285 (2008).

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4.  Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 121 FERC ¶ 61,260 (2007) (December 14 Clarification Order).

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5.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 (2008).

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6.  July 17 Clarification Order, 124 FERC ¶ 61,055.

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7.  Id. P 5.

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8.  Order No. 697-B, FERC Stats. & Regs. ¶ 31,285.

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9.  Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 126 FERC ¶ 61,072 (2009) (Order Granting Extension of Time to Comply).

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10.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at Appendix C.

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11.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 440.

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13.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 176 (emphasis in original).

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15.  Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at P 38.

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16.  American Wind January 21, 2009 Rehearing Request at 5.

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17.  Id. at 5-6.

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18.  Id. at 6-7.

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19.  Id. at 7.

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21.  Id. at 8.

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22.  Id. at 9.

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23.  Id. at 11.

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25.  See id. at 6 (stating that “in developing a 100 MW project using 1.5 MW wind turbines (approximately 65 turbines), a developer may seek to initially have under control 10,000 acres of land.”).

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26.  Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146, at P 270 (2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ¶ 31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).

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27.  Id. P 114.

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28.  See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 446; 1018 (explaining that the Commission will allow intervenors to rebut the presumption that a seller's ownership of, control of or affiliation with entities that own or control inputs to electric power production do not allow a seller to raise entry barriers).

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29.  Section 1 of the LGIP adopted in Order No. 2003 defines “site control” as “documentation reasonably demonstrating: (1) Ownership of, a leasehold interest in, or a right to develop a site for the purpose of constructing the Generating Facility; (2) an option to purchase or acquire a leasehold site for such purpose; or (3) an exclusivity or other business relationship between Interconnection Customer and the entity having the right to sell, lease or grant Interconnection Customer the right to possess or occupy a site for such purpose.” Order No. 2003, FERC Stats. & Regs. ¶ 31,146, LGIP § 1. The same requirements apply to small generators and wind generating facilities. See Order No. 2006, FERC Stats. & Regs. ¶ 31,180, Small Generator Interconnection Procedures § 1.5; Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs. ¶ 31,186, order on reh'g, Order No. 661-A, FERC Stats. & Regs. ¶ 31,198 (2005).

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30.  See LGIP § 3.3.1 (stating that “[t]o initiate an Interconnection Request, Interconnection Customer must submit all of the following: (i) a $10,000 deposit, (ii) a completed application in the form of Appendix 1, and (iii) demonstration of Site Control or a posting of an additional deposit of $10,000. Such deposits shall be applied toward any Interconnection Studies pursuant to the Interconnection Request. If Interconnection Customer demonstrates Site Control within the cure period specified in Section 3.3.3 after submitting its Interconnection Request, the additional deposit shall be refundable; otherwise, all such deposit(s), additional and initial, become non-refundable.”).

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31.  We note that if a term other than “site control” is used to describe the specific means by which site control is demonstrated in the interconnection process, then the reporting requirement will be triggered when a demonstration of site control is made under that term. For example, “site exclusivity” is considered as the specific means by which site control is determined in the California Independent System Operator's (CAISO's) Generator Interconnection Process Reform tariff amendment. See California Independent System Operator Corp., 124 FERC ¶ 61,292, at P 40-41, 63 (2008). Therefore, the demonstration of “site exclusivity” in the interconnection process set forth in the CAISO's Generator Interconnection Process Reform tariff amendment will trigger the quarterly requirement to report a seller's acquisition of control of a site or sites for new generation capacity development.

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32.  In this context, “control” refers to “site control” as it is defined in the LGIP, or as explained in footnote 31.

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33.  A change in status includes, but is not limited to, the following: Ownership or control of generation capacity that results in net increases of 100 MW or more, or of inputs to electric power production, or ownership, operation or control of transmission facilities, or affiliation with any entity not disclosed in the application for market-based rate authority that owns or controls generation facilities or inputs to electric power production or that owns, operates or controls transmission facilities, or affiliation with any entity that has a franchised service area. See 18 CFR 35.42.

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34.  The relevant geographic markets include those defined in Order No. 697 and those defined in subsequent Commission orders. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 231-32, 237.

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35.  We note that if a site is later expanded to allow for additional generation capacity development and such expansion results in an increase of 100 megawatts or more, a seller will be required to file a notification of change in status to notify the Commission of such a change within 30 days after the end of that quarter.

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36.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447.

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37.  Id. P 817 (citing North American Electric Reliability Corporation, Glossary of Terms Used in Reliability Standards at 2 (2007), available at ftp://www.nerc.com/​pub/​sys/​all_​updl/​standards/​rs/​Glossary_​02May07.pdf)).

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38.  Id. P 830.

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39.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 333.

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40.  Id. P 334.

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41.  Id. n.464.

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42.  Id. P 335.

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43.  Id. P 336.

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44.  Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at P 77 (citing Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 336).

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45.  E.ON January 21, 2009 Rehearing Request at 3, 5.

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46.  Id. at 8.

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47.  Id. at 10.

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48.  Id. at 12.

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49.  Id. at 13.

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50.  Pinnacle January 21, 2009 Rehearing Request at 5.

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51.  Id. at 3-4.

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52.  Id. at 4.

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53.  MidAmerican January 21, 2009 Rehearing Request at 6.

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54.  Id. at 7-8.

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55.  Id. at 8.

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56.  Xcel January 21, 2009 Request for Clarification at 7.

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57.  Id. at 5.

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58.  Id. at 8.

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59.  We note that EEI's request for rehearing of the mitigated sales tariff provision is out-of-time insofar as EEI did not raise issues concerning mitigated sales at the metered boundary on rehearing of Order Nos. 697 and 697-A and appears to be an attempt to re-litigate the determinations made by the Commission in those orders.

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60.  EEI January 22, 2009 Corrected Rehearing Request at 5-6.

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61.  Id. at 3.

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62.  Id. at 8-9.

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63.  Id. at 9.

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64.  In its request for an extension of time to comply with the revised mitigated sales tariff provision, Tampa Electric states that it supports EEI's request for rehearing. On January 28, 2009, the Commission issued an order granting Tampa Electric's request for an extension of time to comply with the tariff provision on mitigated sales at the metered boundary as revised in Order No. 697-B until such time as the Commission issues an order on rehearing of Order No. 697-B. Order Granting Extension of Time to Comply, 126 FERC ¶ 61,072; see supra P 6.

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65.  NRECA and APPA January 27, 2009 Answer at 1-2.

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66.  Id. at 3-4.

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68.  Pinnacle West Capital Corp., 115 FERC ¶ 61,064, at P 8 (2006) (citing CMS Midland, Inc., Midland Cogeneration Venture Limited Partnership, 56 FERC ¶ 61,177, at 61,361 (1991), aff'd sub nom. Michigan Municipal Cooperative Group v. FERC, 990 F.2d 1377 (D.C. Cir. 1993), cert. denied, 510 U.S. 990 (1993)).

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71.  CMS Midland, Inc., Midland Cogeneration Venture Limited Partnership, Midland Cogeneration Venture Limited Partnership, 56 FERC ¶ 61,177, at 61,631 (1991) (footnote omitted).

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72.  Pinnacle West Capital Corp., 115 FERC ¶ 61,064, at P 8 (2006) (citing The Montana Power Company, Confederated Salish and Kootenai Tribes of the Flathead Reservation, 85 FERC ¶ 61,400, at 62,535 (1998)).

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73.  EEI January 21, 2009 Rehearing Request at 9.

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74.  In Wisconsin Gas v. FERC, 758 F.2d 669, 674 (D.C. Cir. 1985) the court stated that, to meet the irreparable injury test for granting a stay:

“First, the injury must be both certain and great; it must be actual and not theoretical. Injunctive relief “will not be granted against something merely feared as liable to occur at some indefinite time,” Connecticut v. Massachusetts, 282 U.S. 660, 674, 75 L. Ed. 602, 51 S. Ct. 286 (1931); the party seeking injunctive relief must show that “the injury complained of [is] of such imminence that there is a `clear and present' need for equitable relief to prevent irreparable harm.” Ashland Oil, Inc. v. FTC, 409 F. Supp. 297, 307 (D.D.C.), aff'd, 179 U.S. App. D.C. 22, 548 F.2d 977 (D.C. Cir. 1976) (citations and internal quotations omitted).”

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75.  In granting Tampa Electric's request for extension of time to comply with the tariff provision on mitigated sales at the metered boundary as revised in Order No. 697-B, the Commission clarified that affected entities must continue to comply with the mitigated sales tariff provision adopted in Order No. 697-A until such time as the Commission acts on the requests for rehearing of Order No. 697-B. Order Granting Extension of Time to Comply, 126 FERC ¶ 61,072.

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76.  Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at Appendix C.

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77.  Id. P 66-67, 69; E.ON May 21, 2008 Rehearing Request at 12-14, Pinnacle May 21, 2008 Rehearing Request at 4-6.

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78.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 819. The Commission also stated “While we generally agree that it is desirable to allow market-based rate sales into markets where the seller has not been found to have market power, we do not agree that it is reasonable to allow a mitigated seller to make market-based rate sales anywhere within a mitigated market. It is unrealistic to believe that sales made anywhere in a balancing authority area can be traced to ensure that no improper sales are taking place. Such an approach would also place customers and competitors at an unreasonable disadvantage because the mitigated seller has dominance in the very market in which it is making market-based rate sales.” Id.; see also Westar Energy, Inc. v. FERC, No. 08-1196, slip op. at 5 (D.C. Cir. June 12, 2009) (stating that in Order No. 697 the Commission concluded that “it `is unrealistic to believe that' such sales `can be traced to ensure that no improper sales are taking place.' ”) (citation omitted); Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 321.

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79.  See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 335.

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80.  Id. P 336.

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81.  As the Court of Appeals for the District of Columbia Circuit recently confirmed, “a wholesaler * * * can easily comply with the [Commission] rule and still make sales into other regions at market-based rates. A wholesaler simply needs to ensure that title passes at or beyond the metered boundary between the mitigated and non-mitigated areas, instead of inside a mitigated area.” Westar Energy, Inc. v. FERC, No. 08-1196, slip op. at 5 (D.C. Cir. June 12, 2009) (citation omitted).

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82.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 334.

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83.  The revised tariff language set forth in the paragraph above is effective as of the effective date of Order No. 697-A.

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84.  See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at Appendix D. The regions include the Northeast, Southeast, Central, Southwest Power Pool, Southwest, and Northwest.

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85.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 374 (citing December 14 Clarification Order, 121 FERC ¶ 61,260 at P 9) (emphasis in original).

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87.  These entities were included in the Regional Market Power Update Schedule provided in Appendix D to Order No. 697.

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[FR Doc. E9-14784 Filed 6-26-09; 8:45 am]

BILLING CODE 6717-01-P