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Credit Reforms in Organized Wholesale Electric Markets

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Federal Energy Regulatory Commission, DOE.


Final rule; order on rehearing.


In this order on rehearing, the Commission reaffirms in part its determinations in Credit Reforms in Organized Wholesale Electric Markets, Order No. 741, to amend its regulations to improve the management of risk and use of credit in the organized wholesale electric markets. This order denies in part and grants in part rehearing and clarification regarding certain provisions of Order No. 741.


Effective Date: This order will become effective on March 28, 2011.

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Christina Hayes (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6194.

Lawrence Greenfield (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6415.

Scott Miller (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8456.

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Before Commissioners: Jon Wellinghoff, Chairman; Marc Spitzer, Philip D. Moeller, John R. Norris, and Cheryl A. LaFleur.

Order on Rehearing

1. In Order No. 741, the Commission adopted reforms to credit policies used in organized wholesale electric power markets.[1] In the instant order, the Commission addresses requests for rehearing of Order No. 741. The Commission grants rehearing as to its establishment of a $100 million corporate family cap on unsecured credit and extends the deadline for complying with the requirement regarding the ability to offset market obligations to September 30, 2011, with the relevant tariff revisions to take effect January 1, 2012, but denies rehearing in all other respects, as discussed below.

I. Background

2. As noted in Order No. 741, the Commission must ensure that all rates charged for the transmission or sale of electric energy in interstate commerce are just, reasonable, and not unduly discriminatory or preferential,[2] and clear and consistent credit policies are an important element in ensuring rates that are just, reasonable, and not unduly discriminatory or preferential. The management of risk and credit requires a balance between protecting the markets from costly defaults [3] and ensuring that barriers to entry for market participants are not prohibitive.

3. The Commission provided guidance to the industry on appropriate credit policies in Order No. 888 [4] and the Policy Statement on Electric Creditworthiness.[5] Credit policies among the organized wholesale electric markets, however, developed in an incremental manner leading to varying credit practices. Because these variable practices posed a heightened risk to the stability of the organized wholesale electric markets, and especially in light of recent events in the financial markets, the Commission proposed that the different credit practices among the organized wholesale electric markets be strengthened.

4. In Order No. 741, the Commission directed the regional transmission organizations (RTO) and independent system operators (ISO) to revise their tariffs to reflect the following reforms: implementation of shortened settlement timeframes, restrictions on the use of unsecured credit, elimination of unsecured credit in all financial transmission rights (FTR) or equivalent markets,[6] adoption of steps to address Start Printed Page 10493the risk that RTOs and ISOs may not be allowed to use netting and set-offs, establishment of minimum criteria for market participation, clarification regarding the organized markets' administrators' ability to invoke “material adverse change” clauses to demand additional collateral from participants, and adoption of a two-day grace period for “curing” collateral calls.

5. Requests for rehearing were filed by the New York Independent System Operator, Inc. (NYISO), Morgan Stanley Capital Group Inc. (Morgan Stanley), Financial Marketers,[7] the American Public Power Association (APPA), East Texas Cooperatives, Six Cities,[8] Midwest Transmission Dependent Utilities (Midwest TDUs),[9] Twin Cities,[10] and Southern California Edison Company (SCE). The New York Transmission Owners filed an answer.[11]

II. Discussion

A. Use of Unsecured Credit

1. Requests for Rehearing

6. Six Cities and Morgan Stanley seek rehearing of the Commission's requirement that each ISO and RTO revise its tariff provisions to reduce the extension of unsecured credit to no more than $50 million per market participant and $100 million per corporate family.[12]

7. Morgan Stanley argues that the Commission should eliminate the $50 million market participant cap. Morgan Stanley contends that the separate caps—$50 million for a market participant and $100 million for a corporate family—will encourage entities to reconfigure their corporate structures to avoid the $50 million per entity cap and instead use the $100 million corporate family cap. Morgan Stanley asserts that such a structure will increase costs to market participants, making the $50 million cap illusory and generating unnecessary burdens for ISOs and RTOs without a corresponding benefit.[13]

8. Conversely, Six Cities argue that the Commission should eliminate the $100 million corporate family cap. They assert that the Commission did not provide a rational explanation for permitting affiliated entities to impose a greater degree of risk than individual entities, and so should not have allowed the $100 million corporate family cap. Six Cities also argues that the $100 million corporate family cap could run up to $600 million if there was a default in every ISO/RTO.[14]

2. Commission Determination

9. The Commission grants rehearing on this issue. Specifically, the Commission is persuaded that an entity reconfiguring its corporate structure, to avoid the $50 million single-entity cap and to instead take advantage of the $100 million corporate family cap, raises a significant risk that is inconsistent with Order No. 741's intent to lower risk. Additionally, the Commission has taken into consideration Six Cities' point that affiliated entities should not be able to impose a greater risk to the stability of organized wholesale markets than individual entities. We agree that the cumulative danger posed by a $100 million corporate family cap on the use of unsecured credit poses an unacceptable risk to the organized wholesale electric markets; many market participants either themselves or through subsidiaries participate in multiple markets. We agree with Six Cities that the default of a single entity could result in a significant cumulative unsecured exposure if we were to allow the higher $100 million corporate cap for unsecured credit originally permitted in Order No. 741. Socializing such losses to other market participants could lead to even more significant market disruption than merely the default of a single entity. The Commission therefore grants rehearing and finds that the limit on the use of unsecured credit should be no more than $50 million per entity, including the corporate family to which an entity belongs.[15] This is the approach originally suggested by the Commission in its Notice of Proposed Rulemaking [16] and the Commission is persuaded it should return to this proposal.

B. Elimination of Unsecured Credit for Financial Transmission Rights Markets

1. Requests for Rehearing

10. APPA, Midwest TDUs, and Six Cities request rehearing on the Commission's elimination of unsecured credit in the FTR markets.[17] They argue that the Commission erred in eliminating unsecured credit for all participants, particularly load-serving entities.

11. APPA and Midwest TDUs argue that the elimination of unsecured credit in FTR markets will make it financially prohibitive for load-serving entities to obtain and hold long-term FTRs of ten years or more (LTTR).[18] They contend that this is inconsistent with the Commission's responsibilities, under section 217(b)(4) of the Federal Power Act (FPA) [19] and Order No. 681,[20] to enable load-serving entities to secure firm transmission rights on a long-term basis for long-term power supply arrangements to serve their load. At a minimum, they contend, the Commission should direct RTOs and ISOs to implement Order No. 741 in compliance with section 217(b)(4) and Order No. 681. Further, APPA and Midwest TDUs argue that they be allowed to request exemptions under Order No. 741 to ensure that a load-serving entity's access to LTTRs is not impaired.

12. Midwest TDUs further argue that ISOs and RTOs manage risk in the FTR markets by determining the creditworthiness of individual FTR market participants. Moreover, Midwest TDUs contend that load-serving entities are less of a credit risk because their bond resolutions give explicit payment Start Printed Page 10494priority to energy and transmission market service providers over bondholders, in effect giving RTOs/ISOs a security interest in their accounts receivable. APPA also contends that, although the Commission noted the challenges in valuing FTRs, the Commission did not provide guidance in how to address that issue.

13. Six Cities contends that the Commission should not have eliminated unsecured credit for all types and holders of FTRs. Six Cities notes that the CAISO has two types of FTRs: allocated CRRs, which are used by load-serving entities to hedge congestion costs for purchases to serve the needs of native load customers, and auctioned CRRs, which may be purchased by any entity that satisfies CAISO's qualification criteria. Six Cities argues that CAISO should be allowed to differentiate between the two categories in setting credit requirements. Specifically, Six Cities argues that load-serving entities have no obligation to pay for allocated CRRs, thus cannot default. By eliminating unsecured credit for all FTRs without regard to the purpose for purchase, Six Cities argues that the Commission's decision is not reasoned decision-making as required by the Administrative Procedures Act.[21]

2. Commission Determination

14. The Commission denies rehearing. The Commission is not persuaded that the elimination of unsecured credit in the FTR markets is inconsistent with the statutory directive to facilitate access to long-term FTRs. While section 217(b)(4) directs us to exercise our authority under the FPA to “enable[ ] load-serving entities” to “secure” FTRs “on a long-term basis,” the statute does not require that we guarantee the availability of unsecured credit, and does not require that we ignore the risks posed by the use of unsecured credit. Denying unsecured credit does not prohibit load-serving entities from securing long-term FTRs, but rather merely requires use of some other form of financing, e.g., the use of secured credit or the posting of collateral. Moreover, there is nothing in the record to indicate that acquisition of long-term FTRs will be prohibitively expensive. Our reason for eliminating reliance on unsecured credit in the FTR markets is to reduce risk to market participants, including risk to those market participants that are load-serving entities. Those seeking rehearing on this issue have failed to demonstrate that this risk can and should be so readily discounted.

15. Nor is the Commission persuaded that unsecured credit in FTR markets should be allowed for certain market participants based on the “purpose” of the entity engaging in the FTR market. The FTR market exists to hedge, i.e., manage, risk, but there are no guarantees that such hedges, even for load-serving entities, will themselves have no risk. The risk of adverse FTR market outcomes and potential effects on market participants led us to take these actions initially, and are no more or less applicable to some participants than others based on the “purpose” of the participant.[22] Finally, to the extent that certain FTRs have inherently low risk, we expect that the RTO and ISO's credit modeling will result in relatively low collateral requirements.

16. As to the question of how FTRs are valued, as we stated in Order No. 741, this issue is beyond the scope of this proceeding.[23] Regarding the Midwest TDUs' argument that where bond resolutions give explicit payment priority to energy and transmission market service providers over bondholders, in effect giving RTOs/ISOs a security interest in their accounts receivable, first, it is not clear that such payment priority would apply in the event of a default in an FTR market. Furthermore, we are not persuaded that giving such payment priority would provide a level of security comparable to the elimination of reliance on unsecured credit.

C. Ability To Offset Market Obligations

1. Requests for Rehearing

17. Morgan Stanley, SCE, NYISO, and the New York Transmission Owners seek rehearing of the Commission's directive that, if an ISO/RTO wishes to allow netting of amounts owed to a market participant against amounts owed by that participant, the ISO/RTO must revise its tariff to include one of the following options: (1) Establish a central counterparty; (2) require market participants to provide a security interest in their transactions in order to establish collateral requirements based on net exposure; or (3) propose another alternative, which provides the same degree of protection as the two above-mentioned methods.[24]

18. NYISO requests clarification that the Commission intended that, in the absence of a counterparty, security interest, or other alternative, netting would only be prohibited across product or service categories. If the Commission does not grant the clarification, NYISO requests rehearing, arguing that an ISO/RTO be allowed to net amounts owed against amounts receivable if supported by the doctrine of recoupment. NYISO contends that, under the doctrine of recoupment, it is inequitable for a debtor to enjoy the benefits of a transaction without also meeting its obligations, so a market participant's benefits from its sales within a category area are lawfully offset by its obligations related to its purchases within the same product category.[25] NYISO argues that, in the event of a market participant's bankruptcy, the bankruptcy court would allow netting within a product or service category under the doctrine of recoupment.

19. SCE requests a similar clarification, and questions how “gross obligations” is defined. SCE states that the Commission was not clear whether requiring collateral posted to gross obligations would (i) allow for netting within a given market but not between markets, (ii) allow for netting for transactions deemed not to have participated in the markets (e.g. E-schedules), or (iii) disallow netting both within markets and across markets and require credit obligations to be determined on an absolute gross basis.[26]

20. SCE also requests that the Commission extend the time for compliance with this tariff revision until October 1, 2012, or alternatively, clarify that parties may move for an extension of time if needed.[27]

21. Morgan Stanley argues that ISOs and RTOs should not require market participants to post collateral to their gross obligations, especially if they are netting amounts owed against amounts receivable under their tariffs. Morgan Stanley contends that requiring collateral to gross obligations will be very expensive, without corresponding benefits. Morgan Stanley also asserts that “other less costly (and at least as effective) options are available.” [28] Morgan Stanley requests in the Start Printed Page 10495alternative that if the Commission retains this requirement, then it should allow higher levels of unsecured credit to ameliorate the effects of this provision.

2. Commission Determination

22. The Commission denies rehearing. In Order No. 741, the Commission established requirements to minimize risk in the event of bankruptcy (i.e., the options noted in paragraph 117 of Order No. 741, and described above in paragraph 17) out of concern that the effect of a default could be exacerbated by a bankruptcy court decision that does not allow netting. Those concerns exist whether netting is performed within a market product category or across market categories. A market administrator must have legal support to net transactions, whether it serves as a counterparty, has been granted a security interest in the transactions, or employs some other solution, in the event of a legal challenge to set-off during a bankruptcy proceeding.[29] The record before us does not clearly demonstrate that the availability of netting will depend on whether it is within or across product categories, and therefore we deny rehearing on this issue.

23. Our denial of rehearing is based in part on the testimony we received during the May 2010 technical conference. In response to questioning regarding set-off within product markets, Mr. Stephen Dutton suggested that a bankruptcy court would be most likely to allow netting within product categories if the ISO or RTO was acting in the same capacity with respect to amounts owed and amounts owing.[30] In response to Mr. Dutton's comments, Mr. Harold Novikoff asserted that the bankruptcy court would look at a different issue, specifically, whether the ISO or RTO is a party to the transaction.[31] Mr. Iskender Catto reiterated Mr. Novikoff's opinion, indicating that a court would look first to the identity of the counterparty, then the role served by the counterparty.[32] Based on this testimony, we believe that netting within product categories may put an RTO or an ISO at risk, were it to not adopt one of remedies we specified in Order No. 741.

24. The Commission also denies Morgan Stanley's request for rehearing on the issue of posting collateral based on gross obligations; this was merely one option presented in Order No. 741. The Commission provided two other options to meet its requirements on this matter and expressed its willingness to consider yet others that can be shown to provide the same degree of protections as the two other options set out in Order No. 741. In the absence of the RTO or ISO taking advantage of such options, it is appropriate that credit requirements be set based on gross obligations in order to minimize the risk, and costs, of market participant default and a bankruptcy court decision refusing to allow netting; anything less would not adequately protect the market and participants in the markets.

25. As to SCE's request that the Commission delay the required filing date of a compliance filing regarding this requirement to October 1, 2012, we believe that such an extension is excessive. However, we will extend the date for filing tariff revisions to comply with this requirement related to the ability to offset market obligations to September 30, 2011, with the relevant tariff revisions to take effect January 1, 2012.

D. Minimum Criteria for Market Participation

1. Requests for Rehearing

26. APPA, Twin Cities, Six Cities, and Financial Marketers seek rehearing on the Commission's determination that each ISO and RTO should include in its tariff language that sets forth specific minimum participation criteria to be eligible to participate in the organized wholesale electric market, such as requirements related to adequate capitalization and risk management controls.[33]

27. APPA requests that the Commission instruct RTOs and ISOs to avoid unreasonable or onerous conditions on load-serving entities or provide specific exemptions for them if needed. APPA states that smaller, public power load-serving entities present “minimal risk, and related costs,” so they should not have to comply with unreasonable or onerous minimum criteria to participate in the market. Also, a default by such a participant would not pose a risk of significant market disruption.[34]

28. Twin Cities request that the Commission provide stronger guidance on minimum criteria, and require that the criteria be uniform across ISOs and RTOs. Twin Cities state that market participants that participate in several markets are burdened by participating in multiple stakeholder processes and they risk being treated differently by different markets. Twin Cities request that the Commission establish the minimum participation criteria, similar to that of the Commodity Futures Trading Commission (CFTC) and Securities and Exchange Commission (SEC), based on tangible net worth. Similar criteria, established by the Commission to apply to all ISO and RTO markets, would provide regulatory certainty, reduce risk, and promote the goal of Order No. 741.[35]

29. Six Cities requests that the Commission require that minimum participation criteria be tiered or calibrated based on the magnitude of a market participant's positions in the market. Because the size of a participant's positions has an effect on the size of a risk that it poses, there should be a correlation between the market participant's positions and the minimum criteria.[36]

30. Financial Marketers express concern that the minimum criteria will exclude small and mid-size companies, virtual traders, and new entrants from participating in the RTO/ISO markets. They contend that the Commission has praised such participants,[37] and that customers in Midwest ISO have suffered higher prices since Midwest ISO began discouraging virtual trading by allocating high Revenue Sufficiency Guarantee (RSG) charges to virtual transactions.[38] Financial Marketers further argue that the stakeholder process will not protect small companies or new entrants, because large utilities will be able to meet any minimum criteria and have a vested interest in excluding competition.

31. Financial Marketers argue that most smaller companies are fully collateralized, and thus pose no threat. They contend that other markets rely on collateral requirements to curb market Start Printed Page 10496risk, and that the CFTC does not require minimum capitalization.[39]

32. Financial Marketers also note that ISO New England Inc. (ISO-NE) and PJM Interconnection, LLC (PJM) have previously considered minimum participation criteria, but abandoned their efforts after concluding that they would reduce competition, result in greater market power by existing large companies, and not provide any additional protections to the market.[40] Financial Marketers conclude that market participants have developed businesses based on participation in the organized wholesale electric markets, and regulations that would prohibit their participation would result in a regulatory taking that would require compensation.[41]

2. Commission Determination

33. The Commission denies rehearing. In Order No. 741, the Commission deferred to stakeholder processes the determination of reasonable minimum criteria for market participation.[42] Because no market participation criteria have yet to be filed, the Commission cannot determine whether such criteria are or are not reasonable. However, we note that we did not mandate a single set of criteria for all participants in a market,[43] and we see value in Six Cities' suggestion that stakeholders consider whether some criteria can be tiered or calibrated based on, for example, the size of a market participant's positions. Such an approach would allow for differentiation based on a market participant's characteristics, but still reduce the market's exposure to the risk of a default. We remind stakeholders that the Commission will review all criteria, including both market-wide criteria and any tiered or calibrated criteria, when such criteria are filed, to ensure that they are just and reasonable and not unduly discriminatory or preferential.

E. Grace Period To “Cure” Collateral Posting

1. Requests for Rehearing

34. East Texas Cooperatives request rehearing on the Commission's establishment of a two-day grace period to “cure” a collateral call.[44] East Texas Cooperatives assert that the Commission should not have established a uniform two-day period because it was not supported by sufficient evidence and the requirement will be onerous for small market participants with small staffs and constrained budgets. East Texas Cooperatives argue that most ISOs and RTOs already have two- or three-day cure periods, and the matter should have been left to their discretion. Alternatively, the Commission could establish a uniform three-day “cure” period for all entities or, as a last resort, a three-day period for not-for-profit load-serving entities, such as cooperatives, municipalities, and other public power entities.

2. Commission Determination

35. The Commission denies rehearing. In establishing the two-day cure period in Order No. 741, the Commission carefully weighed the needs of market participants with the need for the mitigation of uncertainty when the organized electric wholesale markets are under stress. As we learned during the financial crisis, a market administrator may request additional collateral when the market is under stress. As a result, timely cure of a collateral deficiency is critical. We also note that the CFTC called for a one-day cure period, while others promoted a three-day cure period, and we found—and continue to find—that the two-day cure period strikes a reasonable balance between mitigating uncertainty in the market and providing for the needs of participants.

F. Regulatory Flexibility Analysis

1. Requests for Rehearing

36. APPA, Six Cities, and Financial Marketers challenge the Commission's conclusion that Order No. 741 “will not have a significant economic impact on a substantial number of small entities.” [45] They contend that the Commission should analyze the effect of Order No. 741 on small entities, as required by the Regulatory Flexibility Act (RFA).[46]

37. APPA and Six Cities argue that the Commission erred in determining that small utilities within the balancing authority area of an RTO have a choice as to whether to join the RTO. Because large transmission owners are part of the RTO, they argue, small utilities must join to obtain necessary transmission and ancillary services. APPA estimates that more than a thousand public power distribution systems, plus rural electric cooperatives, are located in states served by RTOs and are “small utilities” within the meaning of RFA. APPA also contends that public power systems have unique financial constraints and may not be able to meet the new financial requirements that RTOs might impose.[47]

38. In support of its argument, Six Cities cites Aeronautical Repair Station Ass'n,[48] in which, they state, the court held that even though air carriers were the direct objects of the rule promulgated by the Federal Aviation Administration (FAA), the employees of the contractors and subcontractors were also subject to the rule. The D.C. Circuit concluded that the FAA was required to analyze the effect of the rule on the contractors and subcontractors.[49] Six Cities argues that the ISOs and RTOs are analogous to air carriers, and market participants can be compared to the contractors and subcontractors which are also directly regulated by the agency's rule.[50]

39. Financial Marketers argue that the Commission did not properly analyze the effect of minimum participation criteria on small financial traders under the RFA. Financial Marketers contend that the Commission's directives will push small financial traders out of ISO/RTO markets and prevent market entry by smaller companies.[51]

2. Commission Determination

40. The RFA requires that, when promulgating a final rule, an agency must conduct an analysis that includes, among other things, “(3) a description of and an estimate of the number of small entities to which the rule will apply or an explanation of why no such estimate Start Printed Page 10497is available; * * * and (5) a description of the steps the agency has taken to minimize the significant economic impact on small entities consistent with the stated objectives of applicable statutes * * *.” [52]

41. Under the RFA, an agency must consider the economic impact on entities directly affected and regulated by the subject regulations. The D.C. Circuit has held that Congress did not, however, intend to require that the agency “consider every indirect effect that any regulation might have on small businesses in any stratum of the national economy.” [53] More recently, the Seventh Circuit compared the holdings in several cases considering the RFA, including Aeronautical Repair Station Ass'n, and described the rule as follows: “Small entities directly regulated by the proposed statute—whose conduct is circumscribed or mandated—may bring a challenge to the RFA analysis or certification of an agency. * * * However, when the regulation reaches small entities only indirectly, they do not have standing to bring an RFA challenge.” [54] The court further stated that, where the regulation “expressly” addresses an entity's actions, that entity is subject to an RFA analysis, and that, although the regulation may affect the actions of other entities, those other entities are not subject to an RFA analysis.[55]

42. We note at the outset that the regulations adopted in this proceeding directly apply to RTOs and ISOs only, not small entities, thus the Commission is not required to assess the impact of the rule on small entities.[56] In contrast to Aeronautical Repair Station Ass'n, in which the regulations expressly required certain actions by small entities, in this rulemaking, the regulations require specific actions only by the RTOs and ISOs.[57] Further, the relevant impact considered under the RFA is the impact of compliance, including “the projected reporting, recordkeeping and other compliance requirements of the proposed rule.” [58] Those obligations are directly imposed on RTOs and ISOs only, and not market participants.

43. Additionally, in issuing Order No. 741, the Commission focused on protecting the organized wholesale electric markets from default by a market participant. In the event of a default by a market participant, the losses related to that default must be socialized among all other market participants, potentially leading to cascading defaults, all leading to adverse effects on customers. The Commission sought to balance measures intended to protect the market and market participants from the risk of a default against the effect of the measures on market participants. For instance, in establishing the cap on unsecured credit,[59] setting the two-day cure period,[60] and, on rehearing, allowing RTOs/ISOs to consider a market participant's level of participation in the market in setting minimum criteria,[61] the Commission has sought to protect the markets and market participants from the risk of a default, while providing consideration of the needs of the market participants themselves.

44. The Commission thus has sought to accommodate market participants' concerns while still meeting its responsibility to protect markets to ensure that the resulting rates are just and reasonable and not unduly discriminatory or preferential under FPA sections 205 and 206; however, we are not obligated to conduct a further analysis under the RFA. The regulations promulgated in Order No. 741 and here direct the actions of the ISOs and RTOs in administering the organized wholesale electric markets. While the regulations may indirectly affect other entities—market participants, including investor-owned utilities, municipalities and cooperatives, and financial marketers, as well as customers of all kinds—we are not required to conduct an analysis under the RFA on such entities in this proceeding.

45. Furthermore, by requiring tariff revisions to protect the markets and market participants from the risk and resulting cost of default by others, we are not only protecting market participants from the risk and resulting costs of default by others, but we are, in particular, protecting those smaller market participants that are least able to withstand a default. Smaller market participants have fewer resources available to them to deal with a default when one occurs, and thus it is particularly important for smaller market participants that the Commission put in place measures that minimize the risk of a default and the resulting cost of a default.

46. Further, we note that ISOs and RTOs are in the best position, in the first instance, to assess to what extent credit practices, as implemented in their markets, will have an adverse effect on their market participants, as well as the potential harm to the market in the event of a default. Thus, as noted in Order No. 741, ISOs and RTOs may, through their stakeholder processes, propose specific exemptions for individual entities whose participation is such that a default would not risk significant market disruptions.[62] We also note that, as the ISOs and RTOs submit their compliance filings, interested persons will have an opportunity to contest the various revisions as filed for individual tariffs, and the Commission remains open to comments on the particular revisions at that time. The Commission, however, will not, at this time, adopt any exemptions.

III. Information Collection Statement

47. The Office of Management and Budget (OMB) regulations require that OMB approve certain information collection requirements imposed by an agency.[63] The revisions in Order No. 741 to the information collection requirements for ISOs and RTOs were approved under OMB Control Nos. 1902-0096. While this order clarifies and revises aspects of the existing information collection requirements, it does not add to these requirements. Accordingly, a copy of this order will be sent to OMB for informational purposes only.

IV. Document Availability

48. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission's Home Page ( and in the Commission'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.

49. From the Commission's Home Page on the Internet, this information is available in the Commission's document management system, eLibrary. The full Start Printed Page 10498text 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 “RM10-13” in the docket number field.

50. User assistance is available for eLibrary and the Commission's website during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or 202-502-6652 (e-mail at, or the Public Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at

V. Effective Date

51. Changes to Order No. 741 adopted in this order on rehearing will become effective March 28, 2011.

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List of Subjects in 18 CFR Part 35

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By the Commission.

Kimberly D. Bose,


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In consideration of the foregoing, the Commission amends part 35, subchapter B, chapter I, title 18, Code of Federal Regulations, as follows:

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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 35.47 is amended by revising paragraph (a) to read as follows:

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Tariff provisions regarding credit practices in organized wholesale electric markets.
* * * * *

(a) Limit the amount of unsecured credit extended by an organized wholesale electric market to no more than $50 million for each market participant; where a corporate family includes more than one market participant participating in the same organized wholesale electric market, the limit on the amount of unsecured credit extended by that organized wholesale electric market shall be no more than $50 million for the corporate family.

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1.  Credit Reforms in Organized Wholesale Electric Markets, Order No. 741, 75 FR 65942 (Oct. 21, 2010), FERC Stats. & Regs. ¶ 31,317 (2010) (Order No. 741).

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3.  In organized wholesale electric markets, defaults not supported by collateral are typically socialized among all other market participants.

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4.  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, at 31,937 (1996) (pro forma OATT, section 11 (Creditworthiness)), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

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5.  109 FERC ¶ 61,186 (2004) (Policy Statement).

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6.  References to FTR markets in this order, as in Order No. 741, also include the Transmission Congestion Contracts (TCC) markets in NYISO and the Congestion Revenue Rights (CRR) markets in California Independent System Operator (CAISO).

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7.  Financial Marketers are comprised of Energy Endeavors LP, Big Bog Energy, LP, Gotham Energy Marketing, LP, Rockpile Energy, LP, Coaltrain Energy, LP, Longhorn Energy, LP, GRG Energy, LLC, MET MA, LLC, Pure Energy, Inc., Red Wolf Energy Trading, LLC, Jump Power, LLC, Silverado Energy LP, JPTC, LLC, Blue Star Energy, LLC, and Tower Research Capital LLC.

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8.  Six Cities are comprised of the Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California.

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9.  Midwest TDUs are comprised of Indiana Municipal Power Agency, Madison Gas & Electric Company, Missouri River Energy Services, Southern Minnesota Municipal Power Agency and WPPI Energy.

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10.  Twin Cities are comprised of Twin Cities Power, LLC, Twin Cities Energy, LLC, TC Energy Trading, LLC, Cygnus Energy Futures, LLC, and Summit Energy, LLC.

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11.  The New York Transmission Owners are comprised of Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc., Long Island Power Authority, New York Power Authority, New York State Electric & Gas Corporation, Niagara Mohawk Power Corporation d/b/a National Grid, Orange and Rockland Utilities, Inc., and Rochester Gas and Electric Corporation.

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12.  Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 49-57.

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13.  Morgan Stanley, November 22, 2010 Request for Rehearing at 4-5 (Morgan Stanley Request).

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14.  Six Cities November 19, 2010 Request for Rehearing at 12-14 (Six Cities Request).

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15.  While a corporate family may choose to have a single member company participate in an RTO/ISO's market, or instead opt to have more than one do so, in either case, the single entity or multiple entities together will have a cap of no more than $50 million.

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16.  See Credit Reforms in Organized Wholesale Electric Markets, Notice of Proposed Rulemaking, 75 FR 4310 (Jan. 27, 2010), FERC Stats. & Regs. ¶ 32,651, at P 19 (2010).

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17.  Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 70-79.

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18.  APPA November 19, 2010 Request for Rehearing at 1-3, 4-9 (APPA Request); Midwest TDUs November 22, 2010 Request for Rehearing (Midwest TDUs Request).

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20.  Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, FERC Stats. & Regs. ¶ 31,226, reh'g denied, Order No. 681-A, 117 FERC ¶ 61,201 (2006).

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21.  Six Cities Request at 3, 10-12 (citing Petal Gas Storage, L.L.C. v. FERC, 496 F.3d 695, 698 (D.C. Cir. 2007), and others).

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22.  The analysis in this paragraph, and the prior paragraph, explains why, as a generic matter, we will not allow exemptions from this requirement of Order No. 741.

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23.  Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 76.

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24.  Id. P 116-22. The Commission also left open the possibility of setting credit requirements based on gross obligations. Id.

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25.  NYISO November 19, 2010 Request for Clarification or Rehearing at 4 (citing In re Peterson Distributing, Inc., 82 F.3d 956 (10th Cir. 1996), and other cases). The New York Transmission Owners support NYISO's arguments. New York Transmission Owners December 8, 2010 Answer.

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26.  SCE November 22, 2010 Request for Clarification or Rehearing at 4 (SCE Request).

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27.  Id. at 5-6.

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28.  Morgan Stanley Request at 6, generally 5-7.

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29.  Section 553 of the Bankruptcy Code, 11 U.S.C. 553, provides that a creditor may offset payments owed to the debtor against payments owed by the debtor, under certain circumstances.

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30.  Testimony at Technical Conference on Credit Reforms in Organized Wholesale Electric Markets, Tr. 93:2-16 (May 11, 2010) (Mr. Stephen Dutton, Barnes & Thornburg).

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31.  Id. at 93:20-94:17 (Mr. Harold Novikoff, Wachtell, Lipton, Rosen & Katz).

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32.  Id. at 94:24-95:11 (Mr. Iskender H. Catto, Kirkland & Ellis on behalf of the Committee of Chief Risk Officers).

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33.  Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 131-34.

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34.  APPA Request at 4-9.

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35.  Twin Cities November 22, 2010 Request for Clarification or Rehearing at 5-7 (Twin Cities Request).

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36.  Six Cities Request at 3, 10-12. Financial Marketers echo these comments. Financial Marketers November 22, 2010 Request for Rehearing at 13 (Financial Marketers Request).

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37.  Financial Marketers Request at 3-4 (citing California Independent System Operator Corp., 107 FERC ¶ 61,274 (2004), and others).

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38.   Id. at 4-5.

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39.  Id. at 29-31.

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40.   Id. at 14-15.

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41.  Id. at 32-33.

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42.  Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 132-33.

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43.  While we did indicate that criteria should apply to all market participants rather than only certain participants, see Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 133, our intent was that there be minimum criteria for all market participants and not that all market participants necessarily be held to the same minimum criteria. For some criteria, holding all market participants to the same minimum criteria may be appropriate. For other criteria, however, it may be appropriate to hold different participants to different minimum criteria, e.g., based on the size of the participants' positions.

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44.  Id. P 160-63.

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45.  Id. P 184. The RFA definition of “small entity” refers to the definition provided in the Small Business Act, which defines a “small business concern” as a business that is independently owned and operated and that is not dominant in its field of operation. 5 U.S.C. 601(3) (citing section 3 of the Small Business Act, 15 U.S.C. 632). The Small Business Size Standards component of the North American Industry Classification System defines a small electric utility as one that, including its affiliates, is primarily engaged in the generation, transmission, and/or distribution of electric energy for sale and whose total electric output for the preceding fiscal years did not exceed 4 million MWh. 13 CFR 121.201 (2010).

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47.  APPA Request at 10.

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48.   Aeronautical Repair Station Ass'n, Inc. v. FAA, 494 F.3d 161 (D.C. Cir. 2007).

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49.  Id. at 177.

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50.  Six Cities Request at 6-9.

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51.  Financial Marketers Request at 18-20.

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52.  5 U.S.C. 604(a)(3), (5).

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53.   Mid-Tex Electric Cooperative v. FERC, 773 F.2d 327, 343 (D.C. Cir. 1985); see also Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855, 868-69 (D.C. Cir. 2001).

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54.  White Eagle Cooperative Association v. Conner, 553 F.3d 467, 480 (7th Cir. 2009).

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56.  Cement Kiln Recycling Coalition, 255 F.3d at 869.

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57.  Aeronautical Repair Station Ass'n, Inc, 494 F.3d at 177.

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58.  Mid-Tex Electric Cooperative, 773 F.2d at 342 (citing 5 U.S.C. § 603(b)(4) and related legislative history).

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59.  Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 50.

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60.  Id. P 161.

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61.  See supra P 33.

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62.  Order No. 741, FERC Stats. & Regs. ¶ 31,317 at P 165. We also note that a market participant retains its right to individually seek an exemption under section 206 of the FPA.

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[FR Doc. 2011-4088 Filed 2-24-11; 8:45 am]