Federal Energy Regulatory Commission, DOE.
Final rule; order on rehearing.
In this order on rehearing, the Federal Energy Regulatory Commission (Commission) affirms its basic determinations in Order No. 719, Wholesale Competition in Regions with Organized Electric Markets, which amended Commission regulations to improve the operation of organized wholesale electric markets in four areas: Demand response, including pricing during periods of operating reserve shortage; long-term power contracting; market-monitoring policies; and the responsiveness of RTOs and ISOs to their customers and other stakeholders. This order denies in part and grants in part rehearing and clarification regarding certain provisions of Order No. 719.
Effective Date: This is effective on August 28, 2009.Start Further Info
FOR FURTHER INFORMATION CONTACT:
Russell Profozich (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. Russell.Profozich@ferc.gov. (202) 502-6478.
Tina Ham (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. Tina.Ham@ferc.gov. (202) 502-6224.End Further Info End Preamble Start Supplemental Information
|A. Summary of Order No. 719||2|
|B. Requests for Rehearing||10|
|A. Demand Response and Pricing During Periods of Operating Reserve Shortages in Organized Markets||13|
|1. Ancillary Services Provided by Demand Response Providers||13|
|a. Request for Rehearing||15|
|b. Commission Determination||16|
|2. Aggregation of Retail Customers||17|
|a. Requests for Rehearing||18|
|b. Commission Determination||41|
|3. Market Rules Governing Price Formation During Periods of Operating Reserve Shortage||72|
|a. Requests for Rehearing||74|
|b. Commission Determination||93|
|B. Long-Term Power Contracting in Organized Markets||107|
|1. Hedging Instruments||108|
|a. Request for Rehearing||109|
|b. Commission Determination||110|
|2. Structural Issues||111|
|a. Request for Rehearing||112|
|b. Commission Determination||117|
|C. Market-Monitoring Policies||123|
|1. Market Mitigation||127|
|a. Requests for Rehearing||129|
|b. Commission Determination||133|
|2. Relationship Between Internal and External MMU||138|
|a. Requests for Rehearing||139|
|b. Commission Determination||141|
|3. State Access to MMU Information||144|
|a. Requests for Rehearing||145|
|b. Commission Determination||146|
|4. Offer and Bid Data||151|
|a. Requests for Rehearing or Clarification||152|
|b. Commission Determination||156|
|5. Ethics Provisions||160|
|a. Request for Rehearing or Clarification||161|
|b. Commission Determination||164|
|6. Referral of Market Design Flaws||167|
|D. Responsiveness of RTOs and ISOs to Customers and Other Stakeholders||171|
|1. Criteria for Responsiveness||172|
|a. Requests for Rehearing||173|
|b. Commission Determination||178|
|2. Hybrid Boards||184|
|a. Requests for Rehearing||186|
|b. Commission Determination||189|
|3. Mission Statements||192|
|a. Requests for Rehearing||193|
|b. Commission Determination||194|
|III. Document Availability||195|
|IV. Effective Date||198|
128 FERC ¶ 61,059
Before Commissioners: Jon Wellinghoff, Chairman; Suedeen G. Kelly, Marc Spitzer, and Philip D. Moeller.
1. On October 17, 2008, the Commission issued a Final Rule  establishing reforms to improve the operation of organized wholesale electric power markets  and amended its regulations under the Federal Power Act (FPA) in the areas of: (1) Demand response, including pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers and other stakeholders. The Commission stated that these reforms are intended to improve wholesale competition to protect consumers in several ways: By providing more supply options, encouraging new entry and innovation, spurring deployment of new technologies, removing barriers to comparable treatment of demand response, improving operating performance, exerting downward pressure on costs, and shifting risk away from consumers.
A. Summary of Order No. 719
2. In the area of demand response, the Commission required each RTO and ISO to: (1) Accept bids from demand response resources in RTOs' and ISOs' markets for certain ancillary services on a basis comparable to other resources; (2) eliminate, during a system emergency, a charge to a buyer that takes less electric energy in the real-time market than it purchased in the day-ahead market; (3) in certain circumstances, permit an aggregator of retail customers (ARC) to bid demand response on behalf of retail customers directly into the organized energy market; and (4) modify their market rules, as necessary, to allow the market-clearing price, during periods of operating reserve shortage, to reach a level that rebalances supply and demand so as to maintain reliability while providing sufficient provisions for mitigating market power.
3. Additionally, the Commission recognized that further reforms may be necessary to eliminate barriers to demand response in the future. To that end, the Commission required each RTO or ISO to assess and report on any remaining barriers to comparable treatment of demand response resources that are within the Commission's jurisdiction. The Commission further required each RTO's or ISO's Independent Market Monitor to submit a report describing its views on its RTO's or ISO's assessment to the Commission.
4. With regard to long-term power contracting, the Commission required each RTO and ISO to dedicate a portion of its Web sites for market participants to post offers to buy or sell power on a long-term basis.
5. To improve market monitoring, the Commission required each RTO and ISO to provide its Market Monitoring Unit (MMU) with access to market data, resources and personnel sufficient to carry out their duties, and required the MMU to report directly to the RTO or ISO board of directors. In addition, the Commission required that the MMU's functions include: (1) Identifying ineffective market rules and recommending proposed rules and tariff changes; (2) reviewing and reporting on the performance of the wholesale markets to the RTO or ISO, the Commission, and other interested entities; and (3) notifying appropriate Commission staff of instances in which a market participant's or the RTO's or ISO's behavior may require investigation.
6. The Commission also took the following actions with regard to MMUs: (1) Expanded the list of recipients of MMU recommendations regarding rule and tariff changes, and broadened the scope of behavior to be reported to the Commission; (2) modified MMU participation in tariff administration and market mitigation, required each RTO and ISO to include ethics standards for MMU employees in its tariff, and required each RTO and ISO to consolidate all its MMU provisions in one section of its tariff; and (3) expanded the dissemination of MMU market information to a broader constituency, with reports made on a more frequent basis than in the past, and reduced the time period before energy market bid and offer data are released to the public.
7. Finally, the Commission established an obligation for each RTO and ISO to establish a means for customers and other stakeholders to have a form of direct access to the RTO or ISO board of directors, and thereby, increase its responsiveness to customers and other stakeholders. The Commission stated that it will assess each RTO's or ISO's compliance filing using four responsiveness criteria: (1) Inclusiveness; (2) fairness in balancing diverse interests; (3) representation of minority positions; and (4) ongoing responsiveness.
8. The Commission stated in the Final Rule that its actions in these four areas are consistent with its duty to improve the operation of wholesale power markets. The Commission also reiterated its statement from the underlying Notice of Proposed Rulemaking that the reforms addressed in this proceeding do not represent the Commission's final effort to improve the functioning of competitive markets for the benefit of consumers. Rather, the Commission will continue to evaluate other specific reforms that may strengthen organized markets.
9. In each of the four areas, the Final Rule required each RTO or ISO to consult with its stakeholders and make a compliance filing that explains how its existing practices comply with the Final Rule's reforms, or its plans to attain compliance.
B. Requests for Rehearing
10. The following entities have filed timely requests for rehearing or for clarification of Order No. 719: American Electric Power Corporation (AEP); American Public Power Association (APPA) and California Municipal Utilities Association (CMUA) (jointly, APPA-CMUA); APPA, CMUA and National Rural Electric Cooperative Association (NRECA) (collectively, Joint Petitioners); Illinois Commerce Start Printed Page 37778Commission; Coalition of Midwest Transmission Customers, NEPOOL Industrial Customer Coalition, and PJM Industrial Customers Coalition (collectively, Industrial Coalitions); Minnesota Public Utilities Commission (Minnesota PUC); National Association of Regulatory Utility Commissioners (NARUC); Public Utilities Commission of Ohio (Ohio PUC); Old Dominion Electric Cooperative (Old Dominion); Potomac Economics, Ltd. (Potomac Economics); Pennsylvania Public Utilities Commission (Pennsylvania PUC); Sacramento Municipal Utility District (SMUD); Transmission Access Policy Study Group (TAPS); and Public Service Commission of Wisconsin (Wisconsin PSC). New York Independent System Operator, Inc. (NYISO) submitted an untimely request for clarification. Additionally, PJM Interconnection, L.L.C. filed a motion for leave to respond and response to the requests for rehearing. Joint Petitioners filed an answer to PJM's motion.
11. We dismiss NYISO's untimely request for clarification of Order No. 719 because it is, in essence, an untimely request for rehearing. The courts have repeatedly recognized that the time period within which a party may file a petition for rehearing of a Commission order is statutorily established at 30 days by section 313(a) of the FPA and that the Commission has no discretion to extend that deadline. Accordingly, the Commission has long held that it lacks the authority to consider requests for rehearing filed more than 30 days after issuance of a Commission order.
12. Rule 713(d)(1) of the Commission's Rules of Practice and Procedure, 18 CFR 385.713(d)(1) (2008), prohibits answers to requests for rehearing. Accordingly, we reject PJM's motion to respond to requests for rehearing and Joint Petitioners' answer to PJM's motion.
A. Demand Response and Pricing During Periods of Operating Reserve Shortages in Organized Markets
1. Ancillary Services Provided by Demand Response Providers
13. The Final Rule required each RTO or ISO to accept bids from demand response resources, on a basis comparable to any other resources, for ancillary services that are acquired in a competitive bidding process, if the demand response resources: (1) Are technically capable of providing the ancillary service and meet the necessary technical requirements; and (2) submit a bid under the generally-applicable bidding rules at or below the market-clearing price, unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate. All accepted bids would receive the market-clearing price. The Commission determined that these requirements would remove barriers to the comparable treatment of demand-side and supply-side resources.
14. In the Final Rule, in response to commenters who asked the Commission to allow energy efficiency resources to bid into the organized markets, the Commission recognized the value of energy efficiency resources. The Commission stated that it has not excluded from eligibility as a provider of ancillary services any type of resource that is technically capable of providing the ancillary service, including energy efficiency resources. However, because this proceeding did not propose to include energy efficiency resources as providers of competitively procured ancillary services, the Commission stated that it did not have an adequate record to address this issue.
a. Request for Rehearing
15. Pennsylvania PUC asserts that the Commission should uphold its “comparable terms and conditions” principle regarding acceptance of demand response resources for ancillary services by requiring each RTO and ISO to file tariff provisions defining energy efficiency resources as resources qualified to bid into energy markets and ancillary services markets upon such terms and conditions as the RTO or ISO may propose. In addition, it asks the Commission to require each RTO and ISO to supply arguments and adequate record evidence in support of such a filing so that the Commission can determine whether energy efficiency resources are being accepted on a comparable basis with any other resources qualified to bid into energy markets and ancillary services markets.
b. Commission Determination
16. The Final Rule does not exclude from eligibility any type of resource that is technically capable of providing an ancillary service, and therefore we disagree with Pennsylvania PUC that the Final Rule leaves in place a barrier to the use of energy efficiency resources that we must remedy on rehearing. An RTO or ISO is free to work with its stakeholders and incorporate energy efficiency resources into its markets on a basis that is appropriate for its region.
2. Aggregation of Retail Customers
17. Order No. 719 required RTOs and ISOs to amend their market rules as necessary to permit an ARC to bid demand response on behalf of retail customers directly into the RTO's or ISO's organized markets, unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate. The Commission determined that allowing an ARC to act as an intermediary for many small retail loads that cannot individually participate in the organized market would reduce a barrier to demand response. The Commission directed RTOs and ISOs to submit compliance filings to propose amendments to their tariffs or otherwise demonstrate how their existing tariffs and market rules comply with the Final Rule.
a. Requests for Rehearing
i. Commission Jurisdiction
18. Several petitioners assert that the Final Rule's ARC requirements exceed the Commission's statutory authority under the FPA. TAPS and Joint Petitioners state that under section 201(a) of the FPA, the Commission's jurisdiction is limited to the transmission of electric energy in interstate commerce and the sale of such energy at wholesale in interstate Start Printed Page 37779commerce. They argue that a retail customer's reduction of energy consumption is neither a wholesale sale of electric energy nor transmission in interstate commerce, and that retail sales are sales of electric energy to end users that are not sales for resale. Joint Petitioners add that a promise not to consume electric energy at a particular time is a product not covered by the plain language of the FPA. TAPS, therefore, concludes that the Commission lacks jurisdiction to modify retail electricity sales by effectively establishing a new rule that authorizes retail customers purchasing electricity (or non-consumption) to resell that electricity into wholesale markets, either directly or through a third party.
19. Joint Petitioners argue that the Final Rule's ARC requirement violates the separation of Federal and State jurisdiction because it effectively requires public power systems and cooperatives to take affirmative action to consider retail aggregation issues. Joint Petitioners state that the majority of these systems do not have laws or regulations addressing end-use customer aggregation. They argue that the Commission has no jurisdiction to require such affirmative action because it is beyond the scope of its legal authority set out in the FPA.
20. Additionally, TAPS argues that States' and relevant electric retail regulatory authorities' laws and regulations do not grant retail customers either the title or a contract right to resell retail electricity (or any such non-consumption). In that respect, TAPS argues that the Final Rule intrudes into retail electric service rates by requiring RTOs and ISOs to accept demand response bids that may be prohibited by State law, without first obtaining confirmation that such transactions are permitted by the relevant electric retail regulatory authority. Joint Petitioners also note that Congress acknowledged that State and local regulation extends to such consumption decisions when it directed State regulators and non-regulated utilities to consider implementing demand response programs at the State and local level in 2007 amendments to the Public Utility Regulatory Policies Act (PURPA). Further, they argue that the Commission failed to explain how it has jurisdiction over the demand response programs of public power systems and cooperatives that are not public utilities, and are therefore exempt, under FPA section 201(f), from the Commission's FPA section 206 authority  Joint Petitioners contend that the Commission cannot “indirectly” claim jurisdiction over non-jurisdictional entities.
21. Ohio PUC argues that third-party aggregation bids should be subject to State regulatory authority or approval. While it agrees that ARCs should be permitted to aggregate smaller loads, it asserts that retail customers and their representatives should not be classified as wholesale customers subject to the Commission's jurisdiction simply because they provide demand response to the wholesale market. Therefore, Ohio PUC contends that the Final Rule should have acknowledged that all contracts by third-party ARCs are subject to State retail jurisdiction and should be subject to State commission approval prior to providing demand response resources to an RTO or ISO.
22. Joint Petitioners ask the Commission to rule on rehearing that in the case of public power systems and cooperative utilities, RTOs and ISOs should not accept ARCs' demand response bids unless a system's relevant electric retail regulatory authority affirmatively informs the RTO or ISO that it permits aggregation by third-party ARCs. They believe that this approach would allow the Commission to encourage demand response while still respecting the State and local retail regulatory authorities. Similarly, TAPS urges the Commission to modify the opt-out structure of the ARC requirements by changing it to an opt-in structure to remedy the jurisdictional defect and to avoid undue burden to small relevant electric retail regulatory authorities. TAPS argues that such modifications would invite relevant electric retail regulatory authorities to contact the RTO or ISO to provide the necessary notification. Joint Petitioners and TAPS state that absent a notification that permission has been granted, the RTO or ISO should presume that sales of demand response in RTO or ISO markets are not permitted.
23. Additionally, TAPS argues that ARCs and other entities bidding demand response into RTO or ISO markets should be required to certify that their sales are permitted. It asserts that it would be difficult for RTOs or ISOs or relevant electric retail regulatory authorities to identify, independently, whether improper sales or aggregation occur. It states that entities bidding demand response into the RTO or ISO wholesale markets are in the best position to identify the specific retail loads and customers involved and to verify that such bids are permitted by the relevant electric retail regulatory authority. It notes that network customers must provide certification to support designation of network resources. Similarly, individual retail Start Printed Page 37780customers and ARCs should be required to certify that their bids and sales of demand response into wholesale markets are permitted under applicable law, and submission by such entities of ineligible demand response bids should be a tariff violation.
24. Further, AEP notes that the Final Rule permits retail customers to participate in an RTO's or ISO's demand program unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate. It seeks clarification as to “whether this exception applies to [s]tate commission-approved tariff provisions that prohibit sales for resale.” 
25. AEP asserts that a State commission in a non-retail choice State should have the opportunity to fully consider and determine whether an RTO or ISO wholesale demand response program is appropriate for that State. AEP is concerned that RTOs and ISOs may interpret the Final Rule's language on the ARC requirement to mean that RTOs and ISOs may proceed with demand response programs in States where retail customers are provided with State regulated average embedded cost rates, unless States specifically opt out of an RTO's or ISO's wholesale demand response program. AEP argues that such an interpretation would allow: (1) Non-choice retail customers with average embedded cost rates an opportunity to arbitrage their load through sales into wholesale markets to the detriment of remaining retail customers in that State; and (2) an RTO or ISO to set new policy without any consideration of unintended consequences to retail customers.
26. Additionally, AEP notes that a retail customer's action could be considered a “resale” when the customer purchases electric service under a retail tariff and then receives compensation for bidding its load into the wholesale market through a demand response program. Therefore, AEP asks that the Commission either clarify the Final Rule to provide that participation in wholesale demand response programs by retail customers does not constitute a “sale for resale,” or require that retail customers seeking to participate in such programs seek such an exception from the applicable State commission.
ii. Burden on Small Entities and Regulatory Flexibility Analysis
27. Several petitioners state that requiring the relevant electric retail regulatory authorities of each public system to consider some type of affirmative action on the ARC issue imposes a significant burden on them. For example, TAPS argues that the Final Rule requires every relevant electric retail regulatory authority, regardless of size, to address whether demand response sales may be bid into an RTO or ISO market and whether ARCs may aggregate demand response within the regulatory authority's jurisdiction. Joint Petitioners argue that, for the majority of retail regulatory authorities, this would be a substantial undertaking requiring a huge learning curve to become familiar with the process and consequently resulting in a lengthy legislative process. Similarly, TAPS asserts that it is a huge undertaking for the city council of every municipal electric system in an RTO or ISO to expressly address this issue through legislation or regulation. TAPS adds that the Final Rule effectively leaves enforcement responsibility with the relevant electric retail regulatory authority by requiring these entities to monitor and challenge any bids and certifications by ARCs that are not permitted within their jurisdiction.
28. Joint Petitioners argue that the Commission erred in certifying that Order No. 719 will not have a significant economic impact on a substantial number of small entities and certifying that the Final Rule complies with the Regulatory Flexibility Act of 1980 (RFA). Joint Petitioners assert that the reasoning underlying this certification is invalid and therefore seek rehearing. They emphasize that, unless public power systems and cooperatives take affirmative action to enact the necessary law or regulation, relevant electric retail authorities could risk having their public power systems' demand response programs undermined and day-to-day system operations disrupted by ARCs' demand response activities. They reiterate that it would be a significant burden for relevant electric retail regulatory authorities of over 1,300 public power systems and 850 distribution cooperatives to take up this issue. Accordingly, Joint Petitioners maintain that the Final Rule's ARC requirement would result in a significant adverse impact on a substantial number of small entities and, therefore, the Commission is required to provide a certification under the RFA.
29. TAPS also argues that by imposing responsibilities on small entities, the Final Rule ignores the RFA's requirements. TAPS disputes the Commission's cite to American Trucking Associations, Inc. v. EPA (American Trucking Associations)  to support its position in the Final Rule that the RFA analysis is not required. It contends that, in that case, the Environmental Protection Agency (EPA) was not required to conduct an RFA analysis because whether the small entities at issue would be burdened by the EPA's action depended on the intermediate, discretionary action of the States. Under Order No. 719, however, TAPS asserts that the RTOs and ISOs have no such discretion to mitigate the impact of the Final Rule's requirements. TAPS further contends that American Trucking Associations does not relieve the Commission of its obligations under the RFA. Therefore, it suggests that the Commission modify the ARC requirement as stated above, to ensure that any relevant electric retail regulatory authority that wishes to allow third-party demand response aggregation could do so, without unduly Start Printed Page 37781burdening hundreds of municipal entities.
30. Joint Petitioners argue that the Commission erred in arbitrarily and capriciously refusing to consider APPA's compromise proposal regarding third-party aggregation. For entities below the RFA size requirement for small utilities, the RTO or ISO would be required to assume that ARC aggregation is not permitted unless the relevant electric retail regulatory authority of such public power system informed the RTO or ISO that it has elected to allow such aggregation. Joint Petitioners note that APPA argued in its NOPR comments that this size-differentiated regime would appropriately balance the Commission's interest in permitting demand-side participation in organized wholesale markets without the undue burden that the Final Rule places on small power systems. Joint Petitioners argue that Order No. 719 noted, but did not address, APPA's compromise proposal.
31. Similarly, TAPS asserts that, at a minimum, any affirmative regulatory action requirement should be restricted to systems that are larger than the RFA threshold of 4 million MWh. An alternative threshold, according to TAPS, would be “those municipals with retail sales of more than 500 million kWh, as used in the PURPA.”  TAPS contends that limiting the application of the Final Rule's requirements in this manner would minimize the burden on small systems associated with either implementation of the Final Rule or compliance with its express prohibition requirement, consistent with the Final Rule's RFA certification.
iii. Effect on Existing Demand Response Programs and on Rates, Metering, and Billing Protocols
32. TAPS argues on rehearing that the Commission failed to: (1) Adequately address the Final Rule's impact on existing demand response programs; and (2) provide sufficient evidence to justify the disruptions to wholesale and retail service that will be created by authorizing retail customers to sell their demand response in wholesale markets.
33. According to TAPS, it requested in its NOPR comments that the Commission take steps not to undermine the existing tariff and contractual arrangements between load-serving entities and their customers for demand response programs. Yet, TAPS asserts, the Commission imposed new requirements without first independently assessing the Final Rule's impact on existing load-serving-entity-administered demand response programs. It asks the Commission to clarify that the Final Rule's ARC requirement would not undermine or require any changes to existing aggregation programs that already function well.
34. According to TAPS, load-serving entity based programs provide significant value to all of their customers because load-serving entities can integrate their demand response programs into their power supply resource planning. This allows interruptions to be predictable and avoids the need to carry planning reserve for interruptible load. TAPS adds that customers can enjoy the protection of load-serving entity power supply planning and aggregation and average cost rates when they do not want to lower their consumption while wholesale prices are high.
35. TAPS argues that the Commission's attempt to direct demand response into the RTO's or ISO's wholesale energy and ancillary services markets will cause load-serving entities to lose the planning benefits that a load-serving-entity-administered demand response program would normally provide. The load-serving entity would need to include in its planning for firm power supply the full loads of its retail customers who sell into wholesale markets or contract with ARCs, as well as carry full planning reserves to meet that load. Thus, TAPS asserts, the value to the load-serving entity and its other customers of avoiding peak block generation investments and additional reserves would be lost.
36. Similarly, Joint Petitioners note that many public power systems and cooperatives have effectively acted as ARCs for their retail customers. This benefits customers because these not-for-profit entities pass on any savings from demand response measures to their customers in the form of lower rates. Joint Petitioners conclude that ARCs' activities would undercut the demand response regimes their public power systems and cooperatives already have in place or are developing by cherry-picking the demand response potential of specific retail customers, and reducing the savings to the customers of the public power system accruing from such programs. Also, they contend that allowing ARCs to selectively choose load-serving entity demand response resources would also deprive those load-serving entities of important resources used to keep rates down for all consumers. Load-serving entities could no longer control individual customers' loads and engage in risk and portfolio management on behalf of their customers.
37. TAPS further argues that, by authorizing retail customers to sell their non-consumption at high spot prices, the Final Rule changes the financial calculation for retail customers considering demand response. TAPS claims that this reduces load-serving entities' or customers' incentives to make the capital investments necessary to achieve significant, permanent reductions in electricity usage, in favor of short-term, peak-hour reductions that garner premium payments from ARCs and the wholesale market. TAPS argues that the load-serving entity's loss of control over its retail customers' demand response could impair the load-serving entity's ability to plan for its load and harness that demand response to reduce the costs of serving all of its customers.
38. Also, TAPS asserts that permitting direct demand response participation in wholesale markets and aggregation by third-party ARCs will significantly affect billing, metering, and settlement for the municipal system at both the wholesale and retail levels. Specifically, it contends that any system implemented by RTOs and ISOs to prevent double-counting could require major modifications to both RTO and ISO metering and settlement protocols and load-serving entities' metering and billing protocols. For example, TAPS states that municipals that allow individual retail customers and third-party ARCs to sell demand response into wholesale markets may be subject to phantom energy charges, based on Start Printed Page 37782the amount of energy that those retail demand responders would otherwise have consumed. Consequently, this could result in deviation charges for load-serving entities for failure to accurately schedule their load. TAPS argues that, if ARC-aggregated load causes an unexpected drop in a load-serving entity's load, the load-serving entity will be subject to uplift charges if its real-time load is below its day-ahead load. Similarly, it adds that a decrease or an increase in a load-serving entity's load, triggered by unexpected, market-price driven demand response, could impose over- and under-scheduling charges on a load-serving entity under the SPP's tariff.
39. Arguing that demand response participation in wholesale markets, either directly or by third-party ARCs, will affect the scheduling and resource planning of the load-serving entities that serve the retail customers providing demand response, TAPS concludes that load-serving entities will need to develop a system for allocating the cost of phantom energy. TAPS believes that load-serving entities should assign those charges only to retail customers whose decision to sell their demand response into the wholesale market caused the load-serving entity to incur those costs. Accordingly, TAPS requests that the Final Rule should be modified to direct RTOs and ISOs to provide detailed information, in real time, to affected load-serving entities on: (1) The identity of all individual retail customer load involved (even if aggregated by an ARC); and (2) the amount of such demand response for each billing interval.
40. TAPS believes that, in total, the costs of accommodating wholesale demand response bids by selected retail customers outweigh the benefits. It asserts that the implementation of the Final Rule to accommodate wholesale demand response bids by retail customers will require RTOs and ISOs and load-serving entities to expend resources for uncertain benefits. For example, TAPS states that RTOs and ISOs will incur significant costs to design brand-new systems to accommodate, track, and verify demand response. Therefore, it asks that the Commission require RTOs and ISOs to evaluate the efficacy of ARC-based demand response programs, especially given the adverse impacts on load-serving-entity-administered demand response programs, and to implement them only if that evaluation demonstrates that the benefits outweigh the costs.
b. Commission Determination
41. In the Final Rule, the Commission adopted the NOPR proposal to require RTOs and ISOs to amend their market rules as necessary to permit an ARC to bid demand response on behalf of retail customers directly into the RTO's or ISO's organized markets, unless the laws or regulations of the relevant electric retail regulatory authority do not permit a retail customer to participate. The Commission reasoned that such an action would reduce a barrier to demand response participation in the organized markets subject to Commission jurisdiction. As discussed below, we affirm this broad finding, but deny in part and grant in part requests for rehearing on this issue.
i. Commission Jurisdiction
42. Although the rehearing requests present the issue of Commission jurisdiction from various points of view and with emphasis on various groups of market participants or activities (and we will answer these arguments in turn), they all include the same basic issue: whether the Commission has jurisdiction to make rules requiring the RTOs and ISOs to accept demand response bids.
43. Section 201(b) of the FPA confers jurisdiction on the Commission over the transmission of electric energy in interstate commerce, and sales of electric energy at wholesale in interstate commerce. Sections 205 and 206 of the FPA confer upon the Commission the responsibility to ensure that rates and charges for transmission and wholesale power sales by public utilities, including any rule, regulation, practice or contract affecting them, are just and reasonable and not unduly discriminatory or preferential. While FPA sections 201(f) and 201(b)(2) make clear that the Commission's authorities under Part II of the FPA do not apply to governmental entities and certain electric cooperatives, except as specifically provided, the Commission's regulation of the organized markets operated by RTOs and ISOs (which are public utilities) nevertheless affects governmental and cooperative entities that participate in those markets.
44. In exercising its FPA section 206 authority to regulate public utility wholesale sales, the Commission concluded that well-functioning competitive wholesale electric markets should reflect current supply and demand conditions, and that wholesale markets work best when demand can respond to the wholesale price. Thus, the Commission began this proceeding with the goal of eliminating those barriers to demand response participation in the organized markets, and to ensure comparable treatment of all resources in these markets. The Final Rule's ARC requirement is one element of the Commission's effort to achieve this goal.
45. Courts have recognized that the Commission has broad authority under the FPA to identify practices that “affect” public utility wholesale rates under the FPA. For instance, most recently, the DC Circuit held that it was within the Commission's jurisdiction to review ISO New England's annual calculation of the minimum amount of wholesale electric capacity that must be available to assure reliable service in the New England region. The court stated that “even if all the [Installed Capacity Requirement] did was help to find the right price, it would still amount to a `practice * * * affecting rates' ” for purposes of Commission authority.Start Printed Page 37783
46. The Commission has found on several occasions that demand response affects wholesale markets, rates, and practices and, therefore, issued orders on various aspects of electric demand response in organized markets. Some of these orders approved various types of demand response programs, including programs to allow demand response to be used as a capacity resource  and as a resource during system emergencies, to allow wholesale buyers and qualifying large retail buyers to bid demand response directly into the day-ahead and real-time energy markets and certain ancillary services markets, particularly as a provider of operating reserves, as well as programs to accept bids from ARCs.
47. Demand response affects public utility wholesale rates because decreasing demand will tend to result in lower prices and less price volatility. The Commission has noted that demand response has both a direct and an indirect effect on wholesale prices. The direct effect occurs when demand response is bid directly into the wholesale market: lower demand means a lower wholesale price. Demand response at the retail level affects the wholesale market indirectly because it reduces a load-serving entity's need to purchase power from the wholesale market. Demand response tends to flatten an area's load profile, which in turn may reduce the need to construct and use more costly resources during periods of high demand; the overall effect is to lower the average cost of producing energy. Demand response can help reduce generator market power: the more demand response is able to reduce peak prices, the more downward pressure it places on generator bidding strategies by increasing the risk to a supplier that it will not be dispatched if it bids a price that is too high. Moreover, demand response enhances system reliability. Thus, because demand response directly affects wholesale rates, reducing barriers to demand response in the organized wholesale markets helps the Commission to fulfill its responsibility, under sections 205 and 206 of the FPA, for ensuring that those rates are just and reasonable.
48. While the Commission, in regulating public utility wholesale sales under the FPA, may act on demand response participation in the organized markets, we emphasize that this proceeding is a very narrowly-focused rule with respect to demand response resources. It directs an RTO or ISO that operates an organized wholesale electric market—a market subject to the Commission's exclusive jurisdiction—to reduce certain barriers to demand response participation in that market. We anticipate that reducing barriers to demand response participation in wholesale markets also may have beneficial effects as described above, including greater price stability and better information for market participants as to where they need to make grid improvements.
49. Several requests for rehearing argue that the Final Rule exceeds this narrow scope, and violates the separation of Federal and State jurisdiction, by requiring load-serving entities, including public power systems and cooperative utilities, to take affirmative action to consider the issue of retail aggregation by ARCs. However, our Final Rule did not challenge the role of States and others to decide the eligibility of retail customers to provide demand response and, as explained below, we are taking additional steps to address the burden allegedly imposed by our Final Rule on smaller entities.
50. Some rehearing requests, including those from TAPS and Joint Petitioners, ask us to assume that an ARC may not participate in RTO or ISO markets if the relevant State or local laws and regulations are unstated or do not clearly allow ARCs to bid into wholesale markets. We will grant rehearing only to the extent consistent with the compromise proposal by APPA and TAPS based on the RFA threshold of 4 million MWh as modified below. The RTO or ISO should not be in the position of having to interpret when the laws or regulations of a relevant electric retail regulatory authority are unclear. While we leave it to the relevant retail authority to decide the eligibility of retail customers, their decision or policy should be clear and explicit so that the RTO or ISO is not tasked with interpreting ambiguities.
51. However, as discussed below, we agree with APPA and TAPS that it is reasonable to take a different approach here with small utilities. The Commission has previously distinguished small utilities using a 4 Start Printed Page 37784million MWh cutoff for purposes of granting waivers from Order No. 889's  standards of conduct for transmission providers  or determining whether a specific cooperative should be considered a non-public utility outside the scope of a refund obligation involving the California energy crisis. Similarly, Congress used the 4 million MWh cutoff in EPAct 2005 when amending exclusions in section 201(f) of the FPA to include small electric cooperatives. Congress also used this same cutoff to exempt small utilities from compliance with any rules or orders imposed under section 211A of the FPA, involving open access by unregulated transmitting utilities. We believe the same considerations underlying those actions by Congress and the Commission apply here. Thus, we will grant rehearing and adopt herein APPA's and TAPS's alternative proposal, with modifications. We direct RTOs and ISOs to amend their market rules as necessary to accept bids from ARCs that aggregate the demand response of: (1) The customers of utilities that distributed more than 4 million MWh in the previous fiscal year, and (2) the customers of utilities that distributed 4 million MWh or less in the previous fiscal year, where the relevant electric retail regulatory authority permits such customers' demand response to be bid into organized markets by an ARC. RTOs and ISOs may not accept bids from ARCs that aggregate the demand response of: (1) The customers of utilities that distributed more than 4 million MWh in the previous fiscal year, where the relevant electric retail regulatory authority prohibits such customers' demand response to be bid into organized markets by an ARC, or (2) the customers of utilities that distributed 4 million MWh or less in the previous fiscal year, unless the relevant electric retail regulatory authority permits such customers' demand response to be bid into organized markets by an ARC.
52. Petitioners argue that the Commission lacks jurisdiction over demand response because a retail customer's decision to reduce energy consumption does not fall within the Commission's authority under section 201 of the FPA. They assert that a reduction in consumption of energy does not constitute a wholesale sale or transmission of electric energy in interstate commerce. Petitioners miss the point. An RTO's or ISO's market rules are subject to our exclusive jurisdiction. These rules cover market bids from generators and from providers of demand response, which directly affect wholesale prices as discussed above. Accordingly, the Commission has found that it has jurisdiction to regulate the market rules under which an RTO or ISO accepts a demand response bid into a wholesale market.
53. The Commission, in acting within its FPA jurisdiction, is also furthering Congressional policy to encourage demand response programs under EPAct 2005:
It is the policy of the United States that time-based pricing and other forms of demand response, whereby electricity customers are provided with electricity price signals and the ability to benefit by responding to them, shall be encouraged, the deployment of such technology and devices that enable electricity customers to participate in such pricing and demand response systems shall be facilitated, and unnecessary barriers to demand response participation in energy, capacity and ancillary service markets shall be eliminated.
54. We recognize that demand response is a complex matter that is subject to the confluence of State and Federal jurisdiction. The Final Rule's intent and effect are neither to encourage or require actions that would violate State laws or regulations nor to classify retail customers and their representatives as wholesale customers, as Ohio PUC asserts. The Final Rule also does not make findings about retail customers' eligibility, under State or local laws, to bid demand response into the organized markets, either independently or through an ARC. The Commission also does not intend to make findings as to whether ARCs may do business under State or local laws, or whether ARCs' contracts with their retail customers are subject to State and local law. Nothing in the Final Rule authorizes a retail customer to violate existing State laws or regulations or contract rights. In that regard, we leave it to the appropriate State or local authorities to set and enforce their own requirements.
55. Finally, with regard to AEP's request for clarification, we note that this proceeding is a very narrowly-focused rule, as discussed above. The clarification that AEP is seeking involves State laws and regulations, and how they are interpreted in relation to the policies contained in this proceeding. It is not within the scope of this rulemaking to interpret individual State laws and regulations.
ii. Burden on Small Entities and Regulatory Flexibility Analysis
56. In regard to arguments concerning the burden of this rule on small entities and the need for RFA analysis, we reiterate that the Final Rule does not require a relevant electric retail regulatory authority to make any showing or to take any action in compliance with the Final Rule. The NOPR specifically stated that those entities directly affected by this proceeding are the six RTOs and ISOs, namely, CAISO, NYISO, PJM, SPP, Midwest ISO, and ISO New England. The Final Rule adopted this approach and established that its requirements, including the ARC requirement, apply only to RTOs and ISOs.
57. TAPS and Joint Petitioners contend that the Commission's requirement that RTOs and ISOs accept bids from ARCs makes it imperative for relevant electric retail regulatory authorities to decide whether ARCs within their jurisdiction may offer demand response into wholesale markets. TAPS and Joint Petitioners argue that it would be a major undertaking for a retail regulator to clarify for an RTO or ISO whether an ARC may aggregate the demand response of retail customers within the service territories of the load-serving entities it regulates. However, these entities have not provided any new arguments on rehearing, and we continue to find that the Final Rule does not require retail regulators to take any action whatsoever. The Final Rule indicated only that the RTO and ISO must accept bids from an ARC unless the laws or regulations of the relevant electric retail regulatory authority do not permit the ARC to bid. It did not require that retail regulators consider this issue or make any representation, nor did it require the RTO or ISO to impose on retail regulators the task of Start Printed Page 37785communicating this lack of permission at all, much less through a complex or burdensome procedure.
58. In its NOPR comments, APPA proposed an alternative approach, which Joint Petitioners and TAPS support on rehearing. APPA suggested that the retail regulators of public power systems that have output of more than 4 million MWh in one year would need to notify their RTOs or ISOs if their local election was to prohibit ARCs from aggregating retail customers. In the case of public power systems that do not meet this size requirement, however, the presumption would be reversed: the RTO or ISO would be required to assume that aggregation was not permitted unless the retail regulator instructed it to do otherwise.
59. In response to those comments, we reiterate that the Commission does not intend to impose any affirmative obligation to act on relevant electric retail regulatory authorities. We will, however, grant rehearing in part and adopt a modified version of APPA's proposal. As indicated above, the Commission believes that using a 4 million MWh cutoff for purposes of distinguishing small utilities is appropriate.
60. Therefore, we direct RTOs and ISOs to amend their market rules as necessary to accept bids from ARCs that aggregate the demand response of: (1) The customers of utilities that distributed more than 4 million MWh in the previous fiscal year, and (2) the customers of utilities that distributed 4 million MWh or less in the previous fiscal year, where the relevant electric retail regulatory authority permits such customers' demand response to be bid into organized markets by an ARC. RTOs and ISOs may not accept bids from ARCs that aggregate the demand response of: (1) The customers of utilities that distributed more than 4 million MWh in the previous fiscal year, where the relevant electric retail regulatory authority prohibits such customers' demand response to be bid into organized markets by an ARC, or (2) the customers of utilities that distributed 4 million MWh or less in the previous fiscal year, unless the relevant electric retail regulatory authority permits such customers' demand response to be bid into organized markets by an ARC. Our adoption of a modified version of APPA's alternative proposal provides that relevant electric retail regulatory authorities of small utilities meeting the above-noted criteria need not consider this issue except to permit ARCs to aggregate the demand response of retail customers of such small utilities.
61. With regard to the arguments that the Commission erred by failing to do an RFA analysis, we note that if an agency certifies that the rule will not have a significant economic impact on a substantial number of small entities, as we have done in the Final Rule, it is not required to conduct an RFA analysis. RFA does not require an agency to assess the impact of a rule on all small entities that may be affected by a rule, only those entities that would be directly regulated by the rule. While State and local laws and regulations will determine whether many utilities—large or small—may be affected by this rule, the rule directly regulates only RTOs and ISOs.
62. Further, we reiterate that in American Trucking Associations, the court found that because the States, not EPA, had direct authority to impose regulations on small entities, EPA's rule did not have a direct impact on small entities. Accordingly, based on its holding in Mid-Tex, the court held that EPA is not required to conduct an RFA analysis. We reject TAPS's premise that this case is inapplicable to the issue of whether an RFA analysis is required for Order No. 719 because RTOs and ISOs cannot mitigate the burden allegedly placed on small entities. The court in American Trucking Associations did not hold that whether the small entities at issue would be burdened by the EPA's action depended on the State's intermediate and discretionary action. Rather, the court noted that a State, under its broad discretion to determine how it implements EPA's rule, may choose not to comply with EPA's rule altogether. This would require EPA to adopt an implementation plan of its own and, thereby, impose a direct burden on small entities. The court noted that in such a circumstance, EPA stated that it will do an RFA analysis. Therefore, whether RTOs and ISOs are able to mitigate this burden is not an issue and does not affect the finding that Order No. 719 does not directly impact small entities, as in American Trucking Associations.
63. As stated earlier, the Final Rule does not require relevant electric retail regulatory authorities to take any specific action. As such, there was no direct impact on small entities associated with the draft regulations, and the Final Rule did not require a detailed analysis of alternative proposals that would have allegedly mitigated such a burden. We also note that while the requirements in the Final Rule will have no direct impact on small entities, we recognize the concerns raised by APPA and TAPS. Therefore, as noted above, we grant rehearing and adopt a modified version of APPA's alternative proposal.
64. Each RTO or ISO is required to submit, within 90 days of the date that this order on rehearing is published in the Federal Register, a compliance filing with the Commission, proposing amendments to its tariffs or otherwise demonstrating how its existing tariffs and market design comply with the revisions adopted herein.
iii. Effect on Existing Demand Response Programs and on Rates, Metering, and Billing Protocols
65. In the Final Rule, we found that aggregating small retail customers into larger pools of resources expands the amount of resources available to the market, increases competition, helps reduce prices to consumers, and enhances reliability. Petitioners have not demonstrated to the contrary. For example, petitioners have failed to present evidence that demand response aggregated by an ARC does not have the effect of lowering prices for all customers and maintaining reliability at a lower cost than would have been the case if the RTO or ISO had instead dispatched a resource that submitted a higher bid.
66. However, petitioners argue that the ARC requirement's effect on the existing demand response program of load-serving entities is substantial, and that the Commission failed to adequately consider such effects and certain protocol modifications needed to accommodate the Final Rule's policy. We note that petitioners have not provided clear evidence of such adverse impacts, but have merely asserted that they would occur if retail customers are permitted to participate in wholesale markets via ARCs. Also, petitioners have not shown why the issues they raise cannot be adequately addressed by each RTO and ISO through the Start Printed Page 37786stakeholder process and included as part of the RTO's or ISO's compliance filing. As a result, we find that petitioners' arguments are speculative; they have not persuaded us that the policy decisions made in the Final Rule were the result of error. Therefore, we deny rehearing.
67. TAPS asks us to clarify that the Final Rule would not undermine or require any changes to existing retail aggregation programs. We reiterate that the Final Rule is designed to eliminate barriers to demand response participation in RTO or ISO markets. To that end, the Final Rule requires an RTO or ISO to accept bids into its markets from an ARC, unless the laws or regulations of the relevant electric retail regulatory authority for utilities that had total electric output for the preceding fiscal year of more than 4 million MWh do not permit a retail customer to participate. For smaller systems under the RFA size requirement, ARCs may aggregate retail customers only if affirmatively permitted to do so by the relevant electric retail regulatory authority. Each RTO or ISO is required to work with its stakeholders to propose methods of implementing this requirement in its region. The intent of the Final Rule is not to interfere with, undermine, or change existing demand response programs. Nothing in the Final Rule would require a State or local regulator to take any action or prevent them from: (1) Preserving existing aggregation programs, in whatever fashion is appropriate for its jurisdictional area; or (2) authorizing retail customers, via an ARC, to participate in wholesale markets.
68. TAPS and Joint Petitioners emphasize that existing retail aggregation programs provide significant benefits that would be adversely impacted or lost by the Final Rule's ARC requirement. This is not the proper forum to address these issues, which are for the relevant electric retail regulatory authority to consider. It is up to the relevant electric retail regulatory authorities, if they so choose, to decide whether existing retail aggregation programs provide benefits and whether retail customer participation in wholesale demand response programs, individually or through an ARC, would adversely affect those programs and, if so, whether and how to permit such participation. Therefore, TAPS and Joint Petitioners may raise these issues with the relevant electric retail regulatory authority.
69. TAPS also contends that the Final Rule's ARC requirement will affect billing, metering, and settlement protocols at both the wholesale and retail level because major system modifications are needed to address double counting, phantom energy, and verification measures. TAPS and others also express concern that a load-serving entity may buy too much power if its retail customer bids in demand response and the load-serving entity is unaware of the bid, creating an over-scheduling penalty for the load-serving entity. We note that several RTOs and ISOs currently have demand response programs where demand response resources participate either individually or through an ARC. Some of these RTOs and ISOs have addressed the type of concerns raised by TAPS with regard to double counting, verification procedures, deviation charges and the like. We will require each RTO or ISO, through the stakeholder process, to develop appropriate mechanisms for sharing information about demand response resources to address the concerns raised by TAPS and others. We direct each RTO and ISO, through the stakeholder process, to develop, at a minimum, a mechanism through which an affected load-serving entity would be notified when load served by that entity is enrolled to participate, either individually or through an ARC, as a demand response resource in an RTO or ISO market and the expected level of that participation for each enrolled demand response resource. Finally, we direct each RTO and ISO to submit a compliance filing no later than 180 days from the date of this order indicating how it has complied with these requirements.
70. Therefore, as stated in the Final Rule, we require each RTO or ISO to work with its stakeholders, including load-serving entities and ARCs, to develop and implement protocols that will address those issues and allow ARCs to operate within the organized market. Those protocols should address those issues raised by petitioners, including double-counting, concerns regarding deviation, underscheduling, and uplift or other charges that may be incurred if real-time load is below that scheduled in the day-ahead market, as well as metering, billing, settlement, information sharing and verification measures to be submitted in an RTO's or ISO's compliance filing ordered above.
71. We again reject the argument that the Commission should require RTOs and ISOs to evaluate the efficacy of ARC-based demand response programs given the costs involved in modifying systems to accommodate bids by retail customers and the adverse impact on load-serving entity administered programs. As stated above, RTOs and ISOs, in conjunction with their stakeholders, including ARCs and load-serving entities, are in the best position to decide whether to incur the costs of conducting such an analysis. In recognition of regional differences, the Final Rule directed each RTO and ISO to work with its stakeholders to discuss and resolve concerns, including demonstrating net benefits of its program and to address these issues in its compliance filing with the Commission.
3. Market Rules Governing Price Formation During Periods of Operating Reserve Shortage
72. In the Final Rule, the Commission found that existing RTO and ISO market rules that do not allow prices to rise sufficiently during an operating reserve shortage to allow supply to meet demand are unjust and unreasonable, and may be unduly discriminatory. The Commission stated that these rules may not produce prices that accurately reflect the true value of energy in such an emergency and, by failing to do so, may harm reliability, inhibit demand response, deter new entry of demand response and generation resources, and thwart innovation.
73. The Commission established reforms to remove barriers to demand response by requiring RTOs and ISOs to reform their market rules in such a way that prices during operating reserve shortages more accurately reflect the value of energy during such shortages. The Final Rule required each RTO or ISO to reform or demonstrate the adequacy of its existing market rules to ensure that the market price for energy reflects the value of energy during an operating reserve shortage. Each RTO or ISO may propose in its compliance filing one of four suggested approaches Start Printed Page 37787to pricing reform during an operating reserve shortage, or develop its own alternative approach to achieve the same objectives. The Final Rule also required each RTO or ISO to support its compliance filing with adequate factual support. To that end, the Commission outlined six criteria it will consider in reviewing whether the factual record compiled by the RTO or ISO meets the requirements of the Final Rule. The Final Rule also allowed an RTO or ISO to phase in any new pricing rules for a period of a few years, provided that this period is not protracted.
a. Requests for Rehearing
i. Shortage Pricing Proposal
74. Several petitioners requested rehearing of the Commission's shortage pricing requirement on grounds that the requirement would eliminate price caps during periods when bidders could exercise market power; that customers do not yet have in place the tools to respond to price; that there is not sufficient market mitigation in place to ensure a competitive result; that the Commission did not provide sufficient evidence that its shortage pricing requirement would achieve its stated goals; or that the Commission ignored arguments or evidence provided by NOPR commenters indicating that the Commission's proposal may not achieve the desired results.
75. Joint Petitioners argue that the Commission failed to substantiate its finding that existing RTO and ISO market rules are unjust and unreasonable because they do not allow prices to rise sufficiently during operating reserve shortages. Joint Petitioners state that any higher prices during operating reserve shortages would reflect market power, not efficient shortage pricing. They state that given the existing market power problems in organized markets, raising price caps can result in prices that are inefficiently high. Joint Petitioners note that, in concluding that market power will be adequately mitigated through the shortage pricing requirement, the Commission ignored contrary evidence from APPA and NRECA.
76. Similarly, TAPS states that the Commission must have empirical proof that existing competition would ensure that the actual price is just and reasonable before it permits RTOs and ISOs to remove price caps during emergencies. Yet, according to TAPS, the Final Rule's shortage pricing requirement lacks evidence that existing offer and bid caps actually limit demand response, that lifting such caps will attract investment in generation and demand response sufficient to protect consumers from market power, and that consumers will be able to protect themselves from high prices. In light of contrary evidence, TAPS contends that the Commission must provide evidence that consumers will be able to protect themselves from high prices through demand response programs. For instance, TAPS states that existing evidence indicates that the short-run demand curve for electricity is highly inelastic.
77. SMUD argues that the Commission's decision to lift price and bid caps constitutes an arbitrary and unexplained departure from its precedent. It states that the Commission has previously established that demand response technologies are insufficiently developed to permit the relaxation of bid caps and the Final Rule fails to demonstrate how circumstances are sufficiently different to warrant a change in Commission policy.
78. Joint Petitioners maintain that allowing real-time market-clearing prices to exceed price caps during periods of shortage will increase price volatility, which in turn may increase hedging costs. Industrial Coalitions submit that the Commission should develop metrics for measuring demand elasticity and for evaluating whether higher and more volatile prices actually become a key factor in capital deployment decisions. In support, they argue that demand response infrastructure remains underdeveloped, and therefore cannot serve as a viable check on the exercise of market power.
79. Pennsylvania PUC asserts that without real-time demand response, the Commission's assumption that shortage pricing will represent the true value of supply is false because only supply-side resources will be able to respond to prices and such one-sided markets cannot be protected from the exercise of market power. Joint Petitioners also argue that the Final Rule wrongly concluded that demand response itself will act as a market power mitigation measure based on a faulty assumption that end-use customers will be able to respond to shortage pricing by reducing their demand.
80. Similarly, Old Dominion asserts that the Commission erred in mandating a shortage pricing requirement, without first addressing an approach to eliminate non-price barriers. It contends that the Commission noted, but did not address, its NOPR comments that consumers will face increased prices without the ability to respond to price signals. Old Dominion contends that it is difficult to ascertain whether legitimate market forces or the exercise of market power is the cause of increased prices, and that the solution is not to mandate removal of price protections that are necessary for market-based rates to be just and reasonable. Old Dominion adds that the capacity auction structure under PJM's Reliability Pricing Model is designed to capture scarcity rents; that there should not be double collection through an aggressive shortage pricing construct; and that there is an existing construct that seeks to meet the reliability and incentive goals of the Final Rule. Therefore, it requests that the Commission take up the issue of Start Printed Page 37788whether to mandate shortage pricing only after it has addressed proposals on eliminating barriers to demand response. In the alternative, Old Dominion renews its request that the Commission adopt a presumption that such pricing incentives are not necessary, and require RTOs and ISOs that believe otherwise to make a factual demonstration in support of their proposal.
81. Ohio PUC states that the Commission adopted a proposal to remove bid caps for generation during periods of operating reserve shortage, but should also consider raising bid caps only for demand bids until market power concerns are alleviated and the market for demand response is more fully developed.
82. Joint Petitioners note that if the Commission is serious about including consumer protections, including meaningful market power mitigation mechanisms in RTO and ISO shortage pricing filings, the Commission should require evidentiary hearings regarding the RTO's and ISO's shortage pricing proposals and the sufficiency of their proposed mitigation mechanisms.
83. TAPS contends that the Commission failed to clarify the definition of operating reserve shortage and ignored TAPS's concern that the definition may be too broad. TAPS also notes that the preamble to the Final Rule suggests that the Commission intended to define an operating reserve shortage as falling short of meeting the operating reserve requirements under the reliability standards approved by the Commission under FPA section 215, yet the regulatory text provides a definition without referring to these reliability standards. Therefore, it suggests that the Commission revise the definition to restrict shortage pricing to instances where the RTO or ISO risks being unable to replenish operating reserves within the period specified in applicable reliability standards.
ii. Four Shortage Pricing Approaches and Criteria Requirements
84. Several petitioners requested rehearing of the Commission's shortage pricing approaches on grounds that the Commission failed to consider evidence presented by NOPR commenters that one or more of the approaches will not achieve the desired results; that the Commission did not adequately consider alternative approaches or criteria presented by NOPR commenters; and that the Commission needed to provide more direction to RTOs and ISOs on how to implement its proposal and to provide evidence of its expected benefits.
85. TAPS states that the Commission ignored NOPR comments regarding the defects of the four shortage pricing approaches. TAPS argues that the four approaches are not just and reasonable because they: (1) Fail to protect consumers from market power; (2) are premised on unsupported assumptions about bidding behavior and consumers; (3) require the adoption of particular wholesale market structures that have not been established in all RTOs and ISOs; and (4) may encourage gaming.
86. Joint Petitioners argue that the Commission acted arbitrarily and capriciously by failing to consider evidence from NOPR comments, including those provided by NRECA, that the four shortage pricing approaches will not achieve the Commission's stated goals. They assert that the four approaches will: (1) Fail to protect consumers and lead to unjust and unreasonable rates; (2) undermine reliability or preserve reliability only by unlawfully shifting rents from consumers to generators; (3) encourage behavior by generators that creates emergencies; and (4) not attract new supply resources to real-time or long-term markets.
87. Joint Petitioners and TAPS argue that the Final Rule failed to discuss the merits of NRECA's alternative approach, which was to allow only demand response resources to bid prices higher than the current bid caps during emergencies. Under this approach, Joint Petitioners state that demand response resources would be paid the highest clearing price bid by demand response resources; however, generators would receive the highest capped price bid by generating resources needed to clear the market. TAPS states that this approach would have potential benefits for emergencies, with fewer adverse consequences than any of the Final Rule's four approaches. Therefore, it asks the Commission to address the merits of NRECA's approach and modify the regulatory text to accommodate this approach. Joint Petitioners argue that the Commission acted arbitrarily and capriciously in failing to consider NRECA's detailed arguments and evidence which they claim show that the four shortage pricing approaches will result in unjust and unreasonable rates and charges, not the beneficial results that the Final Rule anticipates.
88. Joint Petitioners assert that generator resources and demand response resources are not similarly situated and, therefore, it is not unjust and unreasonable or unduly discriminatory under the FPA to compensate them differently. According to Joint Petitioners, during generation scarcity, generators already make all of their generation resources available to the market; hence, they can take no additional actions to balance supply and demand. However, they assert that demand response resources are able to take further action to balance supply and demand by reducing their demand. Therefore, the comparability principle does not require that the same price to be paid to both generators and demand responders to bring supply and demand into balance.
89. Joint Petitioners argue that the Commission failed to address APPA's proposal for eight additional criteria intended to better protect consumers from the exercise of market power and unjust and unreasonable rates. They also contend that the Commission failed to address NRECA's request that the Commission require RTOs and ISOs to quantify the benefits of proposed changes and to demonstrate that they exceed the costs, which should include the expected costs of market power.
90. Similarly, TAPS asserts that the Final Rule ignored its NOPR comments for additional criteria to strengthen the factual showing required for RTOs and ISOs in their shortage pricing compliance filings. TAPS believes that its proposed criteria would address market power and provide accountability.Start Printed Page 37789
91. TAPS also seeks rehearing of the Commission's rejection of Pacific Gas & Electric Corporation's (PG&E) proposed additional criteria, especially with regard to the cost effectiveness of the Final Rule's shortage pricing requirements. TAPS argues that the Commission did not provide a reasoned basis for rejecting PG&E's proposed criteria. It adds that the Commission's failure to require any accountability for the costs imposed by the Final Rule's shortage pricing requirements is contrary to the GAO Report's recommendations.
92. Joint Petitioners request that the Commission vacate the relevant criteria and regulations, and undertake a successor rulemaking with a new record to develop demand response pricing policies that meet the statutory requirements of the FPA.
b. Commission Determination
93. The requests for rehearing do not convince us that the policy decisions made in the Final Rule were the result of error. We therefore affirm our finding in the Final Rule that existing RTO and ISO market rules that do not allow for prices to rise sufficiently during an operating reserve shortage to allow supply to meet demand are unjust, unreasonable, and may be unduly discriminatory. The shortage pricing proposal adopted in the Final Rule is intended to correct this issue while providing protection against the exercise of market power. Therefore, we deny rehearing on this issue.
i. Shortage Pricing Proposal
94. Several petitioners state that the Commission lacked evidence for establishing shortage pricing requirements. We disagree. Based on information gathered from three technical conferences  and comments in response to the ANOPR and the NOPR, the Commission found that today's RTO and ISO market rules may not produce rates that accurately reflect the true value of energy during periods of operating reserve shortages. The Commission determined that such inaccurate prices during an emergency may harm reliability, inhibit demand response, deter new entry of demand response and generation resources, and thwart innovation. Therefore, the Commission concluded that RTO or ISO market rules that do not allow for prices to rise sufficiently during an operating reserve shortage to allow supply to meet demand are unjust, unreasonable, and may be unduly discriminatory.
95. We disagree with the arguments that the Final Rule's shortage pricing requirement will result in the exercise of market power or lead to increased price volatility, or that consumers will not be protected from high prices, or that it is a departure from Commission precedent because it removes bid and price caps that are in place to mitigate market power. As stated in the Final Rule, the Commission is not taking any action to remove bid caps or to remove market power mitigation in regional markets. Rather, the Commission is requiring each RTO and ISO to demonstrate that its market rules accurately reflect the value of energy during reserve shortage periods or to propose changes in its rules to achieve this objective. Each of the Commission's four proposals maintains bid and price caps, but would allow price caps to rise during shortage periods provided that the RTO or ISO demonstrates that adequate market power mitigation provisions are in place. Each RTO or ISO also is free to propose other pricing approaches and associated market power mitigation that meet the purposes and criteria described in the Final Rule. The RTOs' and ISOs' compliance filings are subject to Commission review and approval. Also, to guard the consumer against exploitation by sellers, the Commission required each RTO and ISO to adequately address market power issues in the compliance filing and for MMUs to provide their views to the Commission on any proposed reforms.
96. With regard to arguments that the Final Rule provided no evidence that existing shortage pricing rules are inhibiting investment in demand response resources, we note that the issue is not whether existing market rules remain workable. As we have explained many times, one of the Commission's goals in this proceeding is to eliminate barriers to demand response resources' participation in organized energy markets. If, as petitioners foresee, higher shortage prices result from amending market rules, those prices could be expected to attract investment in both demand response technology and generation by providing opportunities for a higher return on investment—and the entry of demand response over time may lead to lower prices in the long run. We are concerned that such investments may not occur under existing rules because, as at least one commenter observed in response to the NOPR “existing market rules do not accurately reflect the value of energy during periods of shortage and, therefore may deter new entry of demand response and generation resources.”  Also, we do not find that it is necessary to develop metrics for measuring demand elasticity or for evaluating the impact that volatile prices may have on capital deployment decisions, as Industrial Coalitions claim. As noted above, the Commission's goal in this proceeding is to eliminate barriers to demand response participation in RTO and ISO markets, and it is reasonable to expect that higher shortage prices will encourage investment in additional generation and demand response resources.
97. In response to TAPS's statement that a highly inelastic demand curve means that consumers cannot protect themselves from high prices, the Commission notes first that demand is not necessarily inelastic when customers have appropriate notice and prices, and second that even a relatively small amount of demand response in a shortage can lower market prices significantly for all customers.
98. Several petitioners assert that customers are not able to respond to prices in real-time and, therefore, demand response mechanisms must be in place before changes to mitigation rules are considered. We agree with Pennsylvania PUC, Old Dominion, Industrial Coalitions, and others that demand response infrastructures remain underdeveloped for many regions. Developing mechanisms to allow prices to reflect the true value of energy during an emergency should encourage development of demand response infrastructure. With improved price Start Printed Page 37790signals, more buyers would find it worthwhile to invest in technologies that allow them to respond to prices. As noted in the Final Rule, full deployment of advanced meters and complete participation by all load is not needed to help cope with operating reserve shortages. Demand response programs that currently allow a fraction of the load to respond can have a significant positive effect on system reliability and help reduce prices for all.
99. With regard to Old Dominion's request that the Commission address each RTO's or ISO's proposal for eliminating barriers to demand response before mandating shortage pricing, and Joint Coalitions' concern that existing demand response cannot check the exercise of market power, we note that the Final Rule requires each RTO and ISO to provide evidence regarding the ability of demand resources to mitigate market power and how market power will be monitored. The Commission will examine the shortage pricing proposals submitted in each RTO's and ISO's compliance filing and will approve the proposals only if they meet the criteria established in the Final Rule.
100. Finally, with regard to TAPS's request for revision of the definition of operating reserve shortage in the regulatory text, we decline to revise the regulatory text because we do not believe the definition is either inadequate or inconsistent with the discussion in the preamble of the Final Rule. The regulatory text provided a short general definition of an operating reserve shortage and the preamble declined to provide a detailed specification of when an operating reserve shortage exists, stating that the North American Electric Reliability Corporation already specifies procedures for determining when a system operator is out of compliance with the reliability standard and therefore when it has an operating reserve shortage. These standards are well known to RTOs and ISOs and their stakeholders. Given that the level of operating reserves required by the reliability standards depend on the characteristic of each system and cannot be correctly reduced to a single number that applies to every system, the Commission found that it would be best not to adopt in these regulations a new and separate specification of when an operating reserve shortage exists. The Commission found that if it were to duplicate the provisions of the reliability standard in this rulemaking, it would be cumbersome for reliability organizations to improve their specifications of when such a shortage exists without also having to seek a change in our regulations. Therefore, we deny rehearing of this request.
101. We reject Joint Petitioners' request that we require by rule an evidentiary hearing to determine the justness and reasonableness of each RTO's and ISO's shortage pricing proposal. We find that at this stage it is premature to establish a requirement for such evidentiary hearings. All concerned parties have now had an opportunity to comment on the RTOs' and ISOs' compliance filings, and the Commission will determine on a case-by-case basis whether evidentiary hearings are warranted. We reject Joint Petitioners' request to vacate the rulemaking provisions on shortage pricing and institute a new rulemaking. We find that the Joint Petitioners have not provided any new arguments or evidence that would warrant such action.
ii. Four Shortage Pricing Approaches and Criteria Requirements
102. Several petitioners find fault with the four shortage pricing approaches, stating that they fail to protect customers from the exercise of market power and lead to other adverse consequences. We find that these petitioners have not raised any new arguments on rehearing and deny rehearing on this issue.
103. We emphasize that the Final Rule did not establish the shortage rates to be implemented, or even one particular approach to shortage pricing. In particular, the Final Rule did not require the first approach of raising bid caps, as some petitioners suggest. Rather, it required RTOs and ISOs to make a compliance filing, in consultation with their customers and other stakeholders, to establish an approach to shortage pricing during periods of operating reserve shortage or to show that their existing rules satisfy the Final Rule. Further, this compliance filing must make several of the demonstrations that petitioners contend are lacking in the Final Rule, such as ensuring that market power is mitigated and gaming behavior is deterred during periods of operating reserve shortages. Only after such filings have been submitted will the Commission determine, case by case for each RTO or ISO, if the existing or proposed pricing rules—which could include, but are not required to include, raising bid caps—are just and reasonable and sufficient to meet the stated goals of this proceeding. The Commission provided a menu of options through the four approaches or any other approach that the RTO or ISO deems appropriate. Therefore, an RTO or ISO and its stakeholders are free to consider approaches other than the four approaches in the Final Rule and propose it to the Commission, provided it satisfies the requirements in the Final Rule.
104. With regard to NRECA's alternative approach for pricing reform, we reiterate that the Final Rule did not mandate any specific approach to shortage pricing. It presented four approaches to shortage pricing, but left the RTOs and ISOs with freedom to develop the solutions that best suit their regions. RTOs and ISOs may consider NRECA's alternative proposal, or others not presented in the Final Rule, as they see fit. We therefore disagree with Joint Petitioners' contention that the Commission erred in failing to require NRECA's proposal and in overlooking evidence that the four approaches will result in unreasonable rates and charges. Such analysis is most appropriately left to the compliance process, where the Commission can examine how the RTO's or ISO's chosen approach or approaches to shortage prices will work in its region.
105. Joint Petitioners and TAPS argue that the Final Rule ignored some proposals for additional criteria aimed at addressing their concerns, including market power and accountability. While the Final Rule did not specifically address the merits of each additional criterion proposed, the Commission considered them in adopting and revising the six criteria from the NOPR. The Commission found that many of the suggestions for additional criteria are already implicitly or explicitly addressed in the adopted criteria. For example, the Commission noted that the criteria already included an analysis of market power mitigation and, therefore, did not see the need to adopt an additional criterion to protect consumers against market power. We therefore continue to find that the criteria adopted in the Final Rule are sufficient to provide a general guideline for designing a shortage pricing approach that addresses market power, accountability, gaming behavior, and Start Printed Page 37791other issues raised by petitioners. Therefore, we disagree that the Final Rule ignored proposals for additional criteria.
106. Similarly, we see no basis to reconsider PG&E's proposed criteria which were: (1) A demonstration that any proposed market rule changes are cost effective; (2) an evaluation that the operating reserve shortage pricing mechanism is adequately coordinated with other key market mechanisms; and (3) an assessment of the readiness of the demand response programs that will be called on to reduce the number and severity of shortage pricing requirements and help to mitigate market power. While each of these is a worthy goal, our intent in this proceeding is to establish a set of broad criteria to serve as a general guideline for all RTOs and ISOs on designing a shortage pricing approach. Nothing will prevent RTOs, ISOs and their stakeholders from considering these goals in the process of drafting their compliance proposal, and indeed, we encourage them to do so if these items are of concern to them. Further, we note that the Final Rule required RTOs and ISOs to address market power issues in their compliance filings, and to provide “an adequate factual record demonstrating that provisions exist for mitigating market power and deterring gaming behavior * * * [, which] could include, but is not limited to, the use of demand resources to discipline bidding behavior to competitive levels during an operating reserve shortage.”  Accordingly, we find that the Commission did not err in rejecting PG&E's narrower request for a readiness assessment.
B. Long-Term Power Contracting in Organized Markets
107. In the Final Rule, the Commission established a requirement that RTOs and ISOs dedicate a portion of their Web sites for market participants to post offers to buy and sell electric energy on a long-term basis. The Commission noted that this requirement was designed to improve transparency in the contracting process so as to encourage long-term contracting for electric power. Requests for rehearing were timely filed with respect to the need to require development of new hedging instruments and to the need for the Commission to address the larger structural causes of problems with the long-term contracting market.
1. Hedging Instruments
108. Several commenters argued in their NOPR comments that the Commission should address the lack of certain financial hedging instruments in organized markets. These commenters argued that providing such hedging instruments would reduce the risk of marginal losses and encourage long-term contracting. In the Final Rule, however, the Commission declined to take any action on hedging instruments.
a. Request for Rehearing
109. SMUD argues in its request for rehearing that exposure to marginal losses, like exposure to congestion charges, poses a substantial risk to market participants interested in long-term bilateral contracts. The absence of a hedging mechanism for marginal losses, SMUD states, is a significant risk factor in long-term contracting. SMUD notes that the Commission encouraged, but did not require, RTOs and ISOs to develop such hedging mechanisms. It argues that this encouragement is not sufficient, and that the Commission should address on rehearing the need for a marginal loss hedging mechanism or explain why one is not needed.
b. Commission Determination
110. The Commission addressed previously SMUD's request for a requirement for a marginal loss hedging instrument in Order No. 681. The Commission found that EPAct 2005 does not require a marginal loss hedge, and that due to the nature of marginal losses, it is more difficult to design a hedge for marginal losses than it is to create one for congestion costs. The Commission again addressed SMUD's request in the order conditionally approving revisions to CAISO's Market Redesign and Technology Upgrade Tariff provisions involving congestion revenue rights. In that order, the Commission found that it would be unreasonable to direct the CAISO to provide a mechanism that is not required by EPAct 2005, and that does not yet exist in workable form elsewhere. In light of the Commission's extensive, and recent, consideration of this issue, and SMUD's failure to propose new arguments here including evidence of a relevant change in circumstances, or a workable hedge for marginal losses, we are not persuaded to grant rehearing. We continue to encourage RTOs and ISOs to explore methods by which they can assist load-serving entities and others to obtain hedges for marginal losses.
2. Structural Issues
111. The Commission received comments prior to the Final Rule arguing that the structure of organized markets was flawed, and advocating that the Commission needed to institute a broader investigation of organized markets to protect consumers. In the Final Rule, the Commission stated that many of the broader issues commenters raised were beyond the scope of the proceeding, and would require further development to be ripe for inclusion in a proceeding. The Commission noted that these issues had been the subject of a technical conference held to discuss the proposals of American Forest & Paper Association and Portland Cement Association. The Commission stated that it continues to review the information it received at the technical conference for possible action.
a. Request for Rehearing
112. APPA-CMUA argue that the Commission erroneously failed to expand the scope of this proceeding to investigate the issue of whether RTO markets are producing just and reasonable rates. They argue that sections 205 and 206 of the Federal Power Act require the Commission to act when it finds evidence of unjust and unreasonable rates.
113. APPA-CMUA note that they, along with other consumer entities, presented evidence to the Commission in this proceeding regarding failures in centralized power markets. These failures include fewer and higher-priced long-term power supply options, the shifting of financial risks to customers, and impediments to construction of new generation resources. APPA-CMUA argue that the Commission did not consider this evidence, but instead found that the scope of the proceeding was limited to four “discrete” areas. APPA filed extensive comments asking the Commission to expand the scope of the proceeding, which it argues were ignored. APPA-CMUA note that APPA also filed comments following the Start Printed Page 37792technical conference held on May 7, 2008, but that there has been no further activity in that docket.
114. APPA-CMUA argue that the Commission's failure to act violates its obligations under the Federal Power Act, and under administrative law generally. They argue that the Commission has a duty to address unjust and unreasonable rates that extends to systemic, marketwide problems. They also argue that the Commission has a legal obligation to investigate if evidence is presented to it that unjust and unreasonable rates are being charged; if the investigation reveals unjust and unreasonable rates, contracts or practices, the Commission must take remedial action. APPA-CMUA cite to the recent United States Supreme Court case in Massachusetts v. EPA, in which the Court found that the EPA possessed not only the statutory authority, but also the responsibility, to regulate greenhouse gas emissions. APPA-CMUA state that the Court found that the EPA's refusal to institute a rulemaking to regulate greenhouse gases contradicted the clear terms of the Clean Air Act, and was arbitrary and capricious. Similarly, they argue, the Commission in this proceeding has not only failed to act, it has failed even to look at the many comments, statements, studies and affidavits in the docket alleging unjust and unreasonable rates.
115. APPA-CMUA also argue that the Commission erred in finding that RTO and ISO markets provide demonstrable benefits to customers. They argue that the Commission cites no support for the finding, and point to evidence in the record from wholesale customers and others calling into question the existence of such benefits. APPA-CMUA cite to the 2008 GAO Report, which they argue found that the Commission has not done the analyses necessary to support its assertions that RTO markets provide demonstrable benefits to wholesale customers and consumers.
116. Finally, APPA-CMUA argue that the Commission failed to address the structural causes underlying the lack of long-term contracting in RTO and ISO regions. They note that the Commission received several comments relating to the over-reliance on spot markets and lack of long-term contracts caused by the structure of markets within the RTO system. However, the Commission declined to order any of the broader measures commenters suggested. APPA-CMUA argue that the Commission's statement that these structural issues were beyond the scope of the proceeding was a non sequitur, since the Commission itself had set the scope of the proceeding. They note the Commission's apparent belief that there is no fundamental problem with long-term contracts, that contracts are merely available at higher prices than in the past. However APPA-CMUA argue that the Commission failed to consider the results of the Synapse Study it presented, which found that there were structural reasons beyond changes in fuel supply that drove buyer reluctance to enter into long-term contracts. They also argue that the current turmoil in the credit markets should cause the Commission to reconsider its decision, as it is going to be difficult to finance new generation facilities in the future without long-term contracts to support them. APPA-CMUA conclude that the Commission effectively ignored many comments, statements, studies and affidavits that indicate that many load-side interests believe that RTOs are charging unjust and unreasonable rates, and that those comments never received the due process that the FPA requires.
b. Commission Determination
117. We find that the Commission did not violate the standards of due process or shirk its duty under the FPA in confining the scope of this proceeding to four specific areas of reform related to the operation of competitive wholesale markets. We deny rehearing on the issue of whether the Commission failed to justify its decision not to expand the scope of this proceeding.
118. APPA-CMUA's argument that the Commission has a legal duty to expand this rulemaking proceeding to address whether and how to systemically revise organized markets is mistaken. As the Supreme Court has ruled, an agency has broad discretion to choose how best to marshal its limited resources and personnel to carry out its delegated responsibilities. While APPA-CMUA cite to the Supreme Court's decision in Massachusetts v. EPA, this decision was based on a specific statute related to EPA action on greenhouse gases, and did not overturn the general rule that agencies have discretion over how to act to carry out their responsibilities. The Supreme Court found that the EPA had refused to act on a specific statutory requirement to regulate greenhouse gases, and that its refusal was not warranted by the statutory text. By contrast, the Commission has not refused its responsibility to ensure just and reasonable rates here. Indeed, FPA sections 205 and 206 form the legal basis for this proceeding.
119. As the Commission stated in the Final Rule, this proceeding was not intended to fundamentally redesign organized markets; rather, the reforms were intended to be incremental improvements to the ongoing operation of organized markets without undoing or upsetting the significant efforts that have already been made in providing demonstrable benefits to wholesale customers. The Commission focused on four discrete areas with the goal of improving competition in organized wholesale electric markets. This determination was based in part upon a desire to create a manageable forum for discussing and implementing those revisions to organized wholesale markets that could be implemented relatively soon. Expanding the scope of the proceeding to encompass the wholesale revision of organized RTO or ISO markets would delay the immediate and necessary market reforms ordered in the Final Rule.
120. We disagree with APPA-CMUA's argument that the Commission has denied it due process by declining to investigate wholesale market operations in general on the basis that doing so is outside the scope of the proceeding that the Commission itself set. If the Commission was obligated to frame every investigation to satisfy commenters' requests, individual commenters would have the power to delay or derail nascent market rules with which they disagreed merely by arguing that the scope of the proceeding was too narrow or too broad. The Commission's goal here is to make improvements to four areas of wholesale market operations.
121. The fact that this proceeding is limited to the four topics addressed above does not indicate that the Commission refuses to act in other areas to ensure just and reasonable rates. For example, the Commission has acted on Start Printed Page 37793a generic basis and with regard to specific regional markets to, among other things, address transmission planning reforms, interconnection rules, and reform of capacity markets, all areas that improve long-term contracting and organized markets as a whole. The Commission continues to review other proposals for reforms, including additional reforms to remove barriers to demand response and reform organized markets. We have received a wealth of information on all sides of these issues, from comments in this proceeding and others, testimony at technical conferences, and other reports such as the recent GAO Report discussed above. Contrary to the claims of APPA-CMUA, the Commission considered all of the comments, statements, studies and affidavits received in this docket when determining the scope and outcome of this proceeding. We appreciate the time and effort put into those submissions, and we remain receptive to the avenues of reform proposed therein.
122. The Commission's policy continues to be to promote competition in wholesale electric power markets. This policy is in keeping with Commission practice and was ratified by Congress in EPAct 2005. We always welcome suggestions for concrete actions that could be taken to improve competition in wholesale markets.
C. Market-Monitoring Policies
123. The Commission ordered a number of reforms in the Final Rule designed to enhance the market monitoring function and thereby to improve the performance and transparency of the organized markets. These reforms centered upon two areas: ensuring the independence of market monitoring units (MMUs) and expanding their information sharing function.
124. To increase the independence of MMUs, the Final Rule directed that MMUs in most instances report directly to the RTO or ISO board of directors or to a committee of the board, rather than to management; directed tariff inclusion of a duty on the part of the RTO or ISO to provide the MMU with access to the data, resources and personnel needed to perform its duties; required the RTO or ISO to set out the expanded functions of the MMU in its tariff; removed the MMU from tariff administration and modified MMU market mitigation functions; prescribed protocols for the referral to Commission staff by the MMU both of market design flaws and of suspected wrongdoing; and required the RTO or ISO to adopt ethics standards for the MMUs and MMU employees.
125. Within the area of information sharing, the Final Rule required the MMU to make quarterly reports in addition to the annual state of the market report, to expand the recipients for the reports, and to hold regular telephone conferences among the MMU and Commission staff, RTO or ISO staff, interested State commissions, State attorneys general and market participants; established procedures for the MMU to share information with State commissions; and reduced the lag time for the release of offer and bid data by the RTO or ISO.
126. Requests for rehearing or clarification were timely filed with respect to the following issues: MMU involvement in market mitigation, the relationship between the internal and external MMU, State access to MMU information, release of offer and bid data, and the scope of the ethics provisions. In addition, the Commission on its own motion clarifies certain duties of the MMU with respect to the referral of market design flaws. These are discussed below.
1. Market Mitigation
127. In the Final Rule, the Commission modified the proposal made in the NOPR that MMUs should be removed from market mitigation. That proposal had been designed to remove the MMU from subordination to the RTO or ISO, and to eliminate the conflict of interest inherent in an MMU opining on the health of the market while itself influencing the market by conducting mitigation. However, a number of commenters objected that there might be a greater conflict of interest in having the RTO or ISO administer mitigation, as it has a vested interest in accommodating its market participants. Commenters raised a number of other objections, including the arguments that the MMU is better equipped than the RTO or ISO to detect the need for mitigation, and that removing the MMU from mitigation would distance it from the market insights it needs for its monitoring function.
128. In order to preserve the advantages of allowing the MMU to perform mitigation, while avoiding entangling it in a conflict of interest, the Final Rule struck a balance between the extremes of removing the MMU entirely from mitigation and allowing unfettered MMU mitigation. It did this in part by providing that an RTO or ISO with a hybrid MMU structure  may permit its internal MMU to conduct mitigation, so long as its external MMU is assigned the task of monitoring the quality and appropriateness of that mitigation. In addition, the Final Rule provided that if the RTO or ISO does not have a hybrid structure, it may still allow its MMU to perform retrospective mitigation, while relegating prospective mitigation to itself. The Final Rule further provided that the MMU could provide the inputs required by the RTO or ISO for prospective mitigation, including the determination of reference levels, the identification of system constraints, calculation of costs, and the like.
a. Requests for Rehearing
129. Old Dominion objects to the removal of prospective mitigation from non-hybrid MMUs, contending that the Commission failed to demonstrate a conflict of interest on the part of MMUs while ignoring what Old Dominion sees as a conflict of interest arising from the RTOs conducting mitigation on what are, in effect, their own customers.
130. Pennsylvania PUC argues that prospective mitigation should not be limited to RTOs and ISOs with hybrid MMUs. It contends that mitigation is performed according to objective tariff criteria, removing the element of discretion, and argues that the record does not establish a need for placing limitations on the performance of mitigation by MMUs.
131. Industrial Coalitions assert that the Commission should not have removed tariff administration and mitigation from the duties of the MMU, arguing that although the Commission intended to strengthen market monitoring, it achieved the opposite effect. They advance the opinion that RTOs and ISOs have demonstrated a Start Printed Page 37794preference for unmitigated outcomes, and therefore should not be given total responsibility for identifying and rectifying abuses of market power.
132. The Ohio PUC and Wisconsin PSC object to what they see as the internal MMU within a hybrid MMU structure having greater mitigation authority than an external MMU. The Ohio PUC opines that some (internal) MMUs will not have the necessary tools to accomplish their job function, which will limit their ability to impose prospective mitigation.
b. Commission Determination
133. The Commission affirms the determination made in the Final Rule as to MMU involvement in mitigation. The arguments raised by petitioners were extensively discussed in comments made during the rulemaking process, and were taken into account by the Commission in reaching its resolution of the issue. The MMU's conflict of interest in conducting mitigation, which one petitioner contends has not been demonstrated, is inherent in the nature of the MMU's duties: inasmuch as the MMU must opine on the quality of its own mitigation when it reports on the health and state of the markets, it cannot be expected to be entirely objective. Conflict of interest concerns do not necessarily rely on historical instances of abuse, but rather on the existence of the conflict itself and on the well-known tendency of human nature to see one's own actions in a favorable light. Furthermore, contrary to that same petitioner's assertion, the Commission did take into account the argument that RTOs and ISOs have conflicts of their own in conducting mitigation. That consideration was, in fact, part of the basis for permitting a substantial degree of mitigation to be performed by the MMUs, both internal and external.
134. Pennsylvania PUC claims that mitigation is non-discretionary, and concludes there is no danger of a conflict of interest influencing the MMU in conducting mitigation. The Commission is of the view that the more objective the criteria for mitigation become, the better and fairer their application will be. However, we realize that there is still a degree of judgment involved in determining whether mitigation is appropriate. If this were not so, mitigation could be entirely automatic, which is not the case. Therefore, conflicts of interest must still be a part of the Commission's consideration in fashioning its rules.
135. The assertion of Industrial Coalitions that RTOs and ISOs have demonstrated a preference for unmitigated outcomes has not been substantiated with record evidence. Other factors can have the opposite effect on an RTO's or ISO's decision to mitigate, such as achieving price moderation, ensuring the orderly and fair administration of the markets, and avoiding MMU referrals to Commission staff due to lax administration. In this regard it is important to observe that any mitigation performed by the RTO or ISO will be monitored by the MMU, and, if the RTO or ISO is not performing its job properly, it will be the duty of the MMU to refer the conduct to Commission staff.
136. Ohio PUC and Wisconsin PSC assume that in an RTO or ISO with a hybrid MMU, the internal MMU has been given more authority in the mitigation area than the external MMU. However, the Final Rule's mitigation provisions provide that the external MMU in a hybrid MMU structure must independently evaluate the performance of the internal MMU, if the latter conducts mitigation. Thus, the external MMU arguably has more authority in the mitigation area than the internal MMU, rather than less.
137. For all the foregoing reasons, the Commission concludes that its resolution of the mitigation and tariff administration issues raised in the NOPR struck the correct balance between unfettered MMU mitigation and no mitigation by the MMU. Therefore, we affirm the Final Rule in this regard and decline to grant rehearing on the issue of MMU involvement in market mitigation.
2. Relationship Between Internal and External MMU
138. The Final Rule did not express a preference for a particular market monitoring structure, whether internal, external, or hybrid. The Commission observed that in light of regional variances and preferences in this regard, each RTO and ISO should decide for itself its own MMU structural relationship. However, the Final Rule did make certain distinctions, depending on the particular MMU structure, as to various duties and responsibilities, including reporting to the board of directors and conducting market mitigation.
a. Requests for Rehearing
139. Ohio PUC questions the efficacy of a hybrid MMU, and proposes that an external market monitor's evaluations and recommendations should prevail over those of the internal MMU. It proposes that mitigation authority not be vested in the internal MMU, presumably because it believes that the internal MMU lacks independence. Ohio PUC also suggests that the responsibilities for data collection, analysis, and all market mitigation and referrals should take place at the external MMU level. It argues that RTOs and ISOs should identify in their tariffs all MMU functions that are essential to the effective operation of the MMU, and delegate them to the external or independent MMU. Ohio PUC argues that the Final Rule results in a dysfunctional MMU hierarchy that will make the existing MMU subordinate to any new internal MMU and the RTO or ISO.
140. Wisconsin PSC supports in their entirety the requests of Ohio PUC. It asserts that the Commission erred in supposedly vesting more authority in the internal MMU in a hybrid structure than in the external MMU, and in failing to clarify that all MMU rules and enforcement standards identified in the RTO or ISO tariff be entrusted to the external MMU.
b. Commission Determination
141. The proposals by petitioners favoring an external MMU appear to be predicated on the notion that an internal MMU necessarily lacks independence. However, as we observed in the Final Rule, we have not detected any deficiency in performance by internal MMUs that is attributable to their structure. Furthermore, the proposition that internal MMUs lack independence ignores the very reforms directed in the Final Rule, one of which provides that an internal MMU that is not part of a hybrid structure must report to the board of directors or to a committee of the board, rather than to management. An internal MMU within a hybrid structure may report to management, but only if it does not perform any of the three core MMU functions, those being identifying ineffective market rules, reviewing the performance of the markets, and making Start Printed Page 37795referrals to the Commission. This reform was instituted precisely to bolster the independence of the MMU performing the core MMU functions.
142. In addition, in a hybrid MMU structure, the internal MMU may conduct market mitigation only if the external MMU is assigned the responsibility and given the tools to monitor the quality and appropriateness of that mitigation. Thus, the external MMU can determine whether mitigation is being adequately performed and, if any deficiencies persist, refer the situation to the Commission. Consequently, the Commission disagrees that a hybrid MMU, with the internal MMU conducting mitigation, will be inferior in performance and independence to an external MMU.
143. The Commission also disagrees with Wisconsin PSC's contention that the internal MMU in a hybrid structure is vested with more authority than the external MMU. As noted above, mitigation may be assigned to the internal MMU within a hybrid structure only if the external MMU is given the tools and responsibility to monitor it, thus arguably giving the external MMU greater authority than the internal MMU. As to other market monitoring duties, these are to be allocated between an internal and external MMU (in a hybrid structure) by the RTO or ISO, with stakeholder approval. Therefore, if petitioners desire that the external MMU should be assigned more of the core MMU functions, they should raise those concerns in the stakeholder process. But whatever allocation results from such process, the Final Rule provides for checks and balances to ensure oversight over the internal MMU's performance, whether by the external MMU or by the board of directors. For all these reasons, we decline to grant the requests for rehearing on the issue of the relationship between external and internal MMUs.
3. State Access to MMU Information
144. One of the two principal goals of the Final Rule's MMU reforms was to expand the content and dissemination of MMU information. One such expansion consists of providing a means by which State commissions can request tailored information from the MMUs. The Commission placed certain restrictions on this right, such as limiting them to general market trends and information, and prohibiting them from being used for State enforcement purposes. This was done so that the MMUs would not be overwhelmed by such requests at the expense of doing their primary job, and to preserve confidentiality where warranted. Because of confidentiality concerns, and also to encourage cooperation by both existing and potential subjects of investigations, the Commission declined to change its policy providing that MMU referrals to the Commission remain confidential.
a. Requests for Rehearing
145. Illinois Commerce Commission argues that tailored requests for information to the MMU by State commissions should not be restricted to general market trends and information, and further contends that there is no evidence that other requests would be time consuming and burdensome. Illinois Commerce Commission also argues that the Commission should not restrict the dissemination of raw data, or forbid State commissions from obtaining information from MMUs for State enforcement activities, as this may conflict with Illinois Commerce Commission's ability under existing tariffs to request MMU information from Midwest ISO or PJM. Lastly, Illinois Commerce Commission proposes that State commissions be informed when an MMU refers a matter concerning market conduct to the Commission. Illinois Commerce Commission argues that there would be no disincentive to entities to self-report if the Commission did so, and contends that State commissions have a proven track record of properly handling confidential information. Minnesota PUC supports the Illinois Commerce Commission's requests in their entirety.
b. Commission Determination
146. Contrary to the assertions in the requests for rehearing, the new provision granting State commissions the right to make tailored requests for information broadens their access to MMU data, rather than restricting it. Objections of the type expressed by Illinois Commerce Commission were addressed in the Final Rule and rejected. While the information sought in tailored requests for information should relate to general market trends and the performance of the wholesale market, the Commission pointed out that the type of information to be provided by the MMU may vary from region to region, and is governed principally by the workload such requests impose on the MMU. Therefore, as discussed in the Final Rule, unless the information violates confidentiality restrictions regarding commercially sensitive material, is designed to aid State enforcement actions, or impinges on the confidentiality rules of the Commission with regard to referrals, it may be produced, so long as it does not interfere with the MMU's ability to carry out its core functions. Subject to these limitations, granting or refusing such requests will be at the MMU's discretion, based on agreements worked out between the RTO or ISO and the States, and subject to the confidentiality provisions in the RTO's or ISO's tariff and to the Commission's confidentiality restrictions.
147. The Commission respectfully disagrees that the confidentiality provisions of the Commission and of the RTOs and ISOs may be overridden, simply because a State asserts it is subject to statutory or regulatory provisions regulating the release of information coming into its possession. The MMUs should not be placed in the position of researching the intricacies of State law on the subject, or predicting how a court might rule on the disclosure of material once it enters the possession of a State commission. While Illinois Commerce Commission contends that the confidentiality provisions of the Final Rule “may conflict” with existing procedures within Midwest ISO and PJM, it fails to explain how. Therefore, no factual basis has been presented upon which to address this objection.
148. As to the time-consuming nature of requests made for State enforcement purposes, the Commission provided evidence in the record to that effect, citing the agency's own long experience with investigations. Furthermore, it would be difficult if not impossible to provide information tailored for enforcement purposes without breaching confidentiality, as such information would be directed toward the activities of individual market participants. As to raw data, the Commission did not forbid an MMU from providing raw data (properly redacted for confidentiality purposes), but stated that if the gathering, organizing, reviewing, and explaining of such data would be too consuming, the MMU was not required to provide it. This is a subset of the Commission's Start Printed Page 37796expressed concern that the MMU not be diverted from its primary MMU duties by requests for information and analysis from State actors.
149. In the Final Rule, the Commission declined to change its long-standing policy of maintaining the confidentiality of MMU referrals to Commission staff. Illinois Commerce Commission contends there would be no disincentive to companies to self-report if such referrals were made public, because MMU referrals do not occur as a result of self-reports. We disagree. If an entity sees that formerly non-public investigations are now being made public, it will be discouraged not only from making self-reports in the future, but also from cooperating and providing data in existing and any future investigations, regardless of the origin of that investigation. Furthermore, as pointed out in the Final Rule, such disclosure could also injure innocent persons who might be erroneously implicated or adversely affected by simply being associated with an investigation.
150. For all these reasons, the Commission declines to grant the requests for rehearing on the issue of tailored requests for information and referrals to the Commission.
4. Offer and Bid Data
151. In the Final Rule, the Commission shortened the period for release of offer and bid data to three months, while retaining the policy of masking the identity of the participants. The Final Rule also incorporated flexibility by allowing RTOs and ISOs to propose a shorter release time or, if they could demonstrate a danger of collusion, a four-month instead of a three-month release, or some alternative mechanism if release of a report were otherwise to occur in the same season as reflected in the data.
a. Requests for Rehearing or Clarification
152. TAPS believes that the reduction of the release period to three months is a step in the right direction, but does not think it goes far enough. It requests more rapid release of offer and bid data, as well as the unmasking of identities. TAPS cites to Australia, England and Wales, all of which it states release data on a near-real-time basis, and contends that information transparency can play a role in the potential mitigation of collusion. TAPS theorizes that the early release of data levels the playing field for smaller market participants and enables them to assist with market monitoring, and argues that greater transparency may help expose attempts to manipulate the market.
153. APPA-CMUA, in a joint filing, support the immediate and full disclosure of offer and bid data, the unmasking of the identity of bidders, and disclosure of system lambdas. They cite the Dunn Study, which the Commission discussed in the Final Rule, for the propositions that “the possible benefits” of posting offer and bid data on the day following the operating day “appear to far exceed” the risks of collusion, and that such release may help expose market manipulation. With respect to the unmasking of identities, APPA-CMUA argue that although the Commission provided that RTOs and ISOs may propose a period when such unmasking might be permitted, this will not happen because generators will argue against such disclosure in the stakeholder process. They further argue that requiring the filing of system lambdas would allow direct analysis of RTO and ISO real-time prices in comparison to the relevant underlying variable generation costs.
154. Illinois Commerce Commission objects to the Commission's continuation of the policy of masking the identities of market participants, and proposes as an alternative that identities be unmasked after a four-month lag, asserting that this time lag would eliminate concerns about participant harm and collusive behavior. The Illinois Commerce Commission contends that an entity's bidding strategy is an important piece of market information, useful in analyzing the reasonableness of market outcomes.
155. Minnesota PUC supports the request for rehearing by the Illinois Commerce Commission in its entirety.
b. Commission Determination
156. Petitioners' objections on this issue were addressed in the Final Rule, and the Commission sees no reason to revisit its determination. The Final Rule provided RTOs and ISOs with a good deal of flexibility to propose a lag period that would work best for its particular situation, and that would meet the desires of its stakeholders. Under the Final Rule, RTOs and ISOs, should they desire, are free to propose petitioners' preferred lag period of only one day.
157. APPA-CMUA contend that generators would object to such a proposal, and would be able to sway the stakeholder process against it. This argument implicitly suggests, without evidence, that not only would the stakeholder process reach a biased and unjust result, but that their proposal is the only correct one. It is also quite possible that the stakeholder process will result in a balancing of petitioners' concerns against those of market participants who may have perfectly rational reasons to prefer delaying the release of offer and bid data, and to mask identities. For example, one such reason is the fact that trading strategies, which is exactly the information sought by petitioners, are trade secrets that have considerable value to market participants. While the Illinois Commerce Commission may wish to use the data for enforcement purposes, other entities may use it to give themselves a competitive advantage, or to eliminate the competitive advantage of another entity. Since the various stakeholders have different concerns and interests, balancing those concerns is more suited to exploration and resolution in the stakeholder process than in this proceeding, at least in the first instance.
158. Likewise, the Final Rule affords flexibility in the area of the masking of identities of market participants placing offer and bid data, by providing that RTOs and ISOs may propose a period for the eventual unmasking of such identities. Again, this allows for a balancing of interests in the stakeholder process. The Commission built this flexibility into its determinations in the area of offer and bid data both to take into account regional differences, and to Start Printed Page 37797give the industry a chance to work with the release period mandated in the Final Rule before deciding whether to propose an even shorter period. Certainly, if an RTO or ISO believes it desirable to release offer and bid data on the day following the operating day, nothing in the Final Rule prevents it from making such a proposal to the Commission, with appropriate justification; in fact, as indicated in the Final Rule, this may be done in the compliance filing to be made in this docket.
159. For all these reasons, the Commission declines to grant the requests for rehearing on the issue of offer and bid data.
5. Ethics Provisions
160. In the Final Rule, the Commission enumerated a number of minimum ethics standards that the RTOs and ISOs are required to adopt for MMUs and their employees. In response to comments filed by the Midwest ISO and Potomac Economics, both of which had requested clarification that any adopted ethics standards need not prohibit MMU employees from performing monitoring for non-RTO or ISO entities, the Commission drew a distinction in the preamble of the Final Rule between entities within and without the RTO or ISO monitored by the MMU. The Final Rule clarified that a monitoring engagement was permissible if the employing entity were not a market participant in the particular RTO or ISO for which the MMU performs market monitoring, but if the employing entity was a market participant in the RTO or ISO for whom the MMU does perform market monitoring, the proposed work would entail the same conflict of interest as would any other consulting services, and would not be allowed.
a. Request for Rehearing or Clarification
161. Potomac Economics argues that the Commission should allow an MMU to perform independent monitoring of an entity other than the RTO or ISO it monitors, whether or not such entity is a participant in the RTO or ISO markets, arguing that such monitoring does not create a conflict of interest. Potomac Economics contends that the interpretation set forth in the Final Rule would harm the MMUs, the affected RTOs and ISOs, and the non-RTO or ISO monitored entities, and would eliminate synergies that would otherwise result from such monitoring. Alternatively, Potomac Economics requests clarification as to which ethics provision is implicated by such activity, and whether erecting a “Chinese Wall” within the MMU would resolve the concern.
162. In support of its position, Potomac Economics argues that the alleged conflict of interest involved in monitoring a non-RTO or ISO entity is no greater than that which exists with respect to the RTO or ISO itself, inasmuch as in both cases the MMU is compensated by its employer. Potomac Economics further observes that such non-RTO or ISO monitoring is done pursuant to contracts filed with the Commission, which provide protections against undue influence (such as forbidding the entity from using its budget process or the threat of replacing the MMU as a means to exert leverage over it).
163. Potomac Economics also argues that unwinding current arrangements providing for such monitoring would impose needless costs on the MMUs, the RTOs and ISOs, and the monitored entities, and would eliminate the improved understanding of the RTO or ISO markets that the MMU gleans from its knowledge of the activities of the monitored entity.
b. Commission Determination
164. After further consideration, the Commission agrees that the objections of Potomac Economics are well-taken. To be clear, the Commission is concerned that allowing a monitor to oversee both the RTO or ISO as well as a market participant operating in the same RTO or ISO for activity in that RTO or ISO may raise a conflict of interest because the monitor may be called upon to opine on its own oversight. However, the Commission is persuaded that the increased insights into the RTO or ISO markets provided by such monitoring may give the MMU useful information, and results in the synergies that Potomac Economics suggests. Therefore, we grant rehearing as set forth below. In an effort to balance the potential benefit of synergies resulting from the monitor overseeing both the RTO or ISO as well as a market participant operating in the same RTO or ISO with our concern over potential conflicts of interest, the Commission will permit an RTO or ISO MMU to enter into contracts to monitor a market participant operating in the same RTO or ISO for activity in that RTO or ISO, under the following conditions: The relationship between the entity and the MMU and the MMU's scope of work for the entity are both mandated by the Commission in an order on the merits, the contract is filed with the Commission for review and approval, and the contract contains a provision that the entity must notify the Commission of any intention to terminate MMU employment, permission for which may be refused by the Commission.
165. In light of this conclusion, it is unnecessary to examine the alternative requests for clarification submitted by Potomac Economics. Furthermore, inasmuch as the Commission's discussion on this point in the Final Rule was advanced as a matter of clarification rather than being based on the language of the regulatory text, we find it unnecessary to amend the regulatory text promulgated in the Final Rule to reach this result. For all these reasons, the Commission grants rehearing on this issue and clarifies the circumstances under which an MMU may perform monitoring services for non-RTO and ISO entities, as set forth in the foregoing discussion.
6. Referral of Market Design Flaws
166. NYISO filed an out-of-time request for clarification regarding the interpretation of certain language contained in the protocols for the referral of market design flaws to Commission staff, which are included in the regulatory text of the Final Rule. Although NYISO's request has been rejected for untimeliness, the Commission finds that it would be useful to provide certain clarifications as to when an MMU is to make referrals, whether the referral is for suspected wrongdoing or for the identification of market design flaws.
167. The operative language in both the protocols for the referral of suspected wrongdoing and the protocols for the identification of market design flaws is the same; that is, an MMU is to make such a referral “in all instances where the Market Monitoring Unit has Start Printed Page 37798reason to believe” either that a market violation has occurred or market design flaws exist that the MMU believes could effectively be remedied by rule or tariff changes. This language is identical to the language that is contained in the existing protocols for referral of suspected wrongdoing, which were promulgated in the 2005 Policy Statement on Market Monitoring Units. The MMUs have had a number of years to become accustomed to the interpretation of this language, and can apply what they have learned from the operation of the existing protocols for suspected wrongdoing to the new protocols for referral of market design flaws.
168. More specifically, this means that the MMUs are to exercise judgment and a certain amount of discretion in deciding what to refer to Commission staff. If the RTO or ISO is already aware of the perceived market design flaw and is timely addressing it, there is no need for the MMU to make a referral to the Commission (although the Commission expects the MMU to apprise the Commission staff on an informal basis of important tariff changes being contemplated by the RTO or ISO). Likewise, if the design flaw is de minimis, there may well be no need to make a referral. When in doubt, the MMU should simply call the appropriate members of Commission staff and discuss the issue. This procedure will provide the MMU with any needed guidance as to whether a filing needs to be made.
169. We find that the foregoing clarification does not require an alteration to the Final Rule's regulatory text, which as indicated simply repeats the language contained in the current protocols for the referral of suspected wrongdoing to Commission staff, and which has historically been interpreted in the manner indicated above.
D. Responsiveness of RTOs and ISOs to Customers and Other Stakeholders
170. In the Final Rule, the Commission required RTOs and ISOs to establish a means for customers and other stakeholders to have a form of direct access to the board of directors, and thereby to increase the boards of directors' responsiveness to these entities. The Commission required each RTO or ISO to submit a compliance filing demonstrating that it has in place, or will adopt, practices and procedures to ensure that its board of directors is responsive to customers and other stakeholders. The compliance filings will be assessed based on four criteria. The Commission also directed each RTO and ISO to post on its Web site its mission statement or organizational charter. Requests for rehearing were timely filed with respect to: the criteria for responsiveness, including the implementation of cost-benefit analyses by RTOs and ISOs and the inclusion of board members with State regulatory experience; the potential for use of hybrid boards; and the lack of a mandate for specific items in the RTO or ISO mission statement.
1. Criteria for Responsiveness
171. In the Final Rule, the Commission adopted four criteria from the NOPR for assessing the filed practices and procedures of each RTO and ISO:
- Inclusiveness—The business practices and procedures must ensure that any customer or other stakeholder affected by the operation of the RTO or ISO, or its representative, is permitted to communicate its views to the RTO's or ISO's board of directors.
- Fairness in Balancing Diverse Interests—The business practices and procedures must ensure that the interests of customers or other stakeholders are equitably considered and that deliberation and consideration of RTO and ISO issues are not dominated by any single stakeholder category.
- Representation of Minority Positions—The business practices and procedures must ensure that, in instances where stakeholders are not in total agreement on a particular issue, minority positions are communicated to the RTO's or ISO's board of directors at the same time as majority positions.
- Ongoing Responsiveness—The business practices and procedures must provide for stakeholder input into the RTO's or ISO's decisions as well as mechanisms to provide feedback to stakeholders to ensure that information exchange and communication continue over time.
The Commission found that additional criteria for responsiveness as proposed by commenters—for example, cost-benefit analyses or cost-containment procedures—were practices and procedures best developed by regional entities and their stakeholders, and therefore not necessary in our regulations. However, many of the other proposed criteria could be considered and, if appropriate, adopted on a regional basis.
a. Requests for Rehearing
172. APPA-CMUA notes that in APPA's comments to the NOPR, it expressed a strong concern that the four criteria proposed by the Commission were so general in nature that it would not be difficult for RTOs to assert that they already satisfy the requirements, and that little change would occur to RTO responsiveness as a result. APPA suggested several concrete measures that the Commission should adopt to ensure responsiveness, including: direct stakeholder access to RTO boards, presentation of minority viewpoints directly to the board, consideration of stakeholder advisory committees and hybrid boards, open RTO board meetings with agendas disclosed in advance, board member attendance at working group/technical meetings where appropriate, elimination of “self-perpetuating” RTO boards, administration of customer satisfaction surveys, development of cost oversight benchmarking for RTOs, and a moratorium on the establishment of new RTO-run markets unless accompanied by an independent cost-benefit analysis or affirmative vote of all RTO stakeholder classes. APPA-CMUA argues that because the Commission declined to adopt additional measures, customers seeking greater RTO responsiveness and accountability will have to participate in RTO stakeholder processes with no clear guidance as to what specific measures will satisfy the four general criteria adopted in the Final Rule. They seek rehearing of this aspect of the Final Rule, and ask the Commission to implement additional measures and criteria to allow for concrete improvements in RTO responsiveness.
173. TAPS also notes that the Commission failed to implement specific requirements for RTO responsiveness or accountability. TAPS points to the suggestions it made in its comments to the NOPR, including requirements for cost-benefit analyses, annual public reporting of RTO performance measurements, requiring RTO management compensation to be tied to consumer-focused performance measures, and an improved budget review process with advance stakeholder review. TAPS also argued that RTOs should be held accountable for fulfilling obligations to plan and expand the transmission system to meet Start Printed Page 37799customers' needs. TAPS argues that the stakeholder process mandated in the Final Rule will not be sufficient to meet the needs it outlined in its comments, and it notes that a recently-released GAO Report confirms the need for Commission action and oversight. Accordingly, TAPS asks the Commission to implement its suggested requirements, or to institute a new NOPR on this topic.
174. SMUD also argues that the Commission should require RTOs and ISOs to implement performance penalties for managers. It notes that the accountability of RTOs for results is distinct from RTO responsiveness. Since RTOs and ISOs are not-for-profit entities, SMUD argues, they cannot be penalized for imprudence. Accordingly, the Commission should address the need for RTOs and ISOs to adopt performance penalties for imprudent decisions by managers.
175. SMUD further argues that the Commission erred in failing to require RTOs and ISOs to conduct cost-benefit analyses before implementing major initiatives. It believes that such a requirement would impose discipline on RTOs and ISOs and improve accountability to stakeholders. SMUD also asserts that the Commission must clarify that, in specific factual situations, the absence of sector representation or procedures for rejecting majority stakeholder positions would violate the responsiveness criteria.
176. Pennsylvania PUC states that the Commission failed to address its concerns regarding the control of board election procedures by RTO or ISO employees or managers. Pennsylvania PUC argues that this issue touches on board “capture” by RTO or ISO management, and is not sufficiently addressed by the Final Rule.
b. Commission Determination
177. The Commission reviewed the proposals for new criteria and board practices in preparing the Final Rule and found that neither more specific criteria nor additional criteria from the Commission were necessary or appropriate. We deny rehearing on this issue.
178. The criteria established for responsiveness were intended to balance the need to improve RTOs' and ISOs' responsiveness to their stakeholders with the development of practices that best suit the needs of the individual RTO or ISO. We continue to believe that this process best works through collaboration between the RTO or ISO and its stakeholders based on the broad principles laid out by the Commission, rather than through the Commission mandating specific outcomes. Further, RTOs and ISOs are still evolving institutions; they and their stakeholders may want to add, remove, or improve specific responsiveness provisions over time, without being prevented from doing so by Commission codification of today's practices. Many of the specific criteria suggested in the comments prior to the Final Rule and in the requests for rehearing are better addressed through the stakeholder process, where RTOs and ISOs can tailor these ideas to the needs of their regions, and amend them as needed without a change in Commission regulations.
179. In establishing the four criteria for board responsiveness, the Commission's goal was to be sufficiently prescriptive to give RTOs and ISOs a guideline for how to structure their board policies, without being so specific as to micromanage each RTO's and ISO's policy. For instance, although we believe that cost-benefit analyses can be useful in analyzing new projects, we are unconvinced that the Commission should mandate cost-benefit analyses in all circumstances where an RTO or ISO engages in a major initiative. We do not have enough evidence in the record to determine when and how an RTO or ISO should be required to perform a cost-benefit analysis. Instead, in the Final Rule, we encouraged interested parties to raise this idea with individual RTOs or ISOs, and allow the RTO or ISO to work out a policy that is tailored to its needs.
180. The specific requirements raised by APPA, TAPS and others represent the end point of the policy process, and should be the result of a dialogue between RTOs and ISOs and their stakeholders rather than Commission mandate. We are interested here in making sure that stakeholders are able to have a productive dialogue with their RTO or ISO, and the criteria the Commission established in the Final Rule were designed to require that this be done in a way determined by each region.
181. With respect to Pennsylvania PUC's concern regarding the relationship between the RTO or ISO board and the entity's employees, we note that Pennsylvania PUC has not presented any evidence that this is a generic issue for all RTOs and ISOs, and does not make the case that a Commission mandate is necessary or appropriate. Pennsylvania PUC should raise any concerns regarding specific RTO or ISO practices during the stakeholder process for forming the responsiveness practices and procedures for that RTO or ISO. Pennsylvania PUC may raise the issue again with the Commission following the RTO and ISO compliance filings if it believes that its concerns have not been adequately addressed.
182. Similarly, with respect to SMUD's and TAPS' requests for requirements for performance penalties for managers, we continue to encourage, but not require, that executive compensation programs give appropriate weight to responsiveness. As we discuss further below, the Commission mandating specific requirements with respect to board structure or board and management compensation could lead to a slippery slope, and may also be outside the Commission's jurisdiction.
2. Hybrid Boards
183. In the Final Rule, the Commission did not require RTOs or ISOs to adopt a specific form of board structure, whether board advisory committee, hybrid board, or other. The Commission found that a one-size-fits-all approach was not warranted. The Commission did note that it viewed the board advisory committee as a particularly strong mechanism for enhancing responsiveness, and that it expected each RTO and ISO to work with its stakeholders to develop the mechanism that best suits its needs.
184. With respect to hybrid boards, the Commission followed its ruling in Order No. 2000, in which it noted that RTOs and ISOs take many different forms to reflect the various needs of Start Printed Page 37800each region. The Commission denied requests to disallow hybrid boards in this proceeding, reasoning that a hybrid governance structure could be constructed in a way that allows for the expertise of various groups to inform the decision-making process, while still retaining board independence such that no individual market participant is given undue influence over the decisions of the board. The Commission noted that commenters were free to raise objections to the specific hybrid board proposals made by RTOs and ISOs in their compliance filings.
a. Requests for Rehearing
185. Several parties argue that the Commission erred in allowing RTOs and ISOs to choose to create hybrid boards. For instance, Illinois Commerce Commission argues that board advisory committees are a superior method of promoting responsiveness, and that the Commission should remove the option of hybrid boards based on their many flaws. Pennsylvania PUC argues that allowing hybrid boards would be at odds with the principle of independence established by the Commission in Orders No. 888  and 2000. Pennsylvania PUC argues that hybrid boards are a bad idea for several reasons, including the difficulty hybrid board members would have in fulfilling their fiduciary duties, the potential for confrontation among members of a sector, and the inability to protect confidential information from disclosure or misuse.
186. Industrial Coalitions state that the Commission failed to present adequate evidence that hybrid boards could be appropriately independent and responsive. They argue that an RTO's or ISO's independence depends on the independence of its board members, and that a hybrid board would, by definition, violate this independence requirement. Additionally, Industrial Coalitions argue that a hybrid board structure would expose independent board members to undue influence from stakeholder interests on the board, which could lead to a divisive atmosphere and suspicion. Finally, they note that it is unlikely that a hybrid board would provide adequate representation to end-use customers, and would likely actually diminish customers' voice.
187. The Ohio PUC argues that the Commission erred in not preventing stakeholders from participating in RTO or ISO boards, and that this decision will erode confidence in RTO or ISO boards because they will be perceived to be biased and to lack independence. Both the Ohio PUC and the Wisconsin PSC also argue that the Commission erred in not ensuring that States' interests are adequately represented on RTO or ISO boards, through seating a board member with State regulatory experience.
b. Commission Determination
188. In the Final Rule, the Commission did not mandate a specific form of board structure, but instead allowed RTOs and ISOs to propose their own methods of meeting the four criteria, including through a board advisory committee or a hybrid board. The Commission heard many of the same arguments against hybrid boards made in the requests for rehearing in comments received prior to the Final Rule. We are aware that this is an issue of some controversy, and we take seriously the potential independence issues that may arise from having stakeholder members on an RTO or ISO board of directors. We emphasize that the Final Rule did not repeal any of the requirements for RTO independence in Order No. 2000 or for ISO independence in Order No. 888. However, we are not convinced that it is impossible to structure a hybrid board so as both to meet the board independence requirements of prior orders and to provide for limited stakeholder membership without compromising board independence. Accordingly, we deny rehearing on this issue.
189. Our ruling does not imply that every form of hybrid board would be acceptable to the Commission. As we stated in the Final Rule, any board that includes market participants should be structured to ensure that no one class would be allowed to veto a decision reached by the rest of the board, and that no two classes could force through a decision opposed by the rest of the board. We continue to view the board advisory committee as a particularly strong mechanism for enhancing responsiveness, and we will closely review any RTO or ISO proposal to ensure that it is just and reasonable and the result of a thorough stakeholder process.
190. We also deny the requests to require that RTO and ISO boards include one member with State regulatory experience. While we believe that a variety of backgrounds and experiences may be useful for an RTO or ISO board, we do not see a reason for the Commission to set generic board membership requirements for all RTOs and ISOs regarding any particular specific experience or qualification. The Ohio Commission and the Wisconsin PSC have not convinced us, in their requests for rehearing, that mandating State regulatory membership would be suited to all circumstances, and therefore we prefer to allow RTOs and ISOs the flexibility to propose for Commission approval their own choices regarding board membership. As previously stated, we will evaluate those proposals in light of the four responsiveness criteria enumerated above.
3. Mission Statements
191. The Final Rule required each RTO and ISO to post on its Web site a mission statement or organizational charter. The Commission encouraged each RTO and ISO to include in its mission statement, among other things, the organization's purpose, guiding principles, and commitment to responsiveness to customers and other stakeholders, and ultimately to the consumers who benefit from and pay for electricity services.
a. Requests for Rehearing
192. Both APPA and TAPS argue that the Commission erred in failing to mandate specific statements in the proposed mission statement posted by the RTO or ISO. APPA notes that the FPA requires that rates be just and reasonable, and thus RTO and ISO mission statements should include explicit language requiring RTOs and Start Printed Page 37801ISOs to provide cost reductions and net benefits to the ultimate consumers they serve. TAPS agrees that the required mission statement should be specific and consumer-focused. TAPS argues that the Commission will not fulfill its obligation under the Federal Power Act unless it redefines the RTOs' and ISOs' mission to include provision of reliable service at the lowest possible reasonable rates, and requires RTOs and ISOs to meet these goals.
b. Commission Determination
193. We deny rehearing of the Commission's decision not to mandate specific statements in the mission statements required of each RTO and ISO. We find, however, that a successful mission statement should explain the mission of an RTO or ISO, as developed in a collaborative process with stakeholders, and we do not wish to interfere with this process by mandating specific elements of the mission statement. Indeed, an RTO's or ISO's mission may evolve over time, and it should be able to update its mission statements to reflect new mission elements. (We note in this regard, as discussed elsewhere in this order, that some petitioners would have us reconsider now the existing mission of some RTOs and ISOs.) If parties believe that an RTO or ISO mission statement is not sufficiently consumer-focused, or is otherwise deficient, they should raise those objections during the stakeholder process or in response to the RTO or ISO compliance filing.
III. Document Availability
194. 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.
195. 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.
196. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) or e-mail at email@example.com, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at firstname.lastname@example.org.
IV. Effective Date
197. Changes to Order No. 719 made in this order on rehearing will be effective on August 28, 2009.Start List of Subjects
List of Subjects in 18 CFR Part 35End List of Subjects Start Signature
By the Commission. Commissioner Kelly is concurring in part and dissenting in part with a separate statement attached.
Nathaniel J. Davis, Sr.,
In consideration of the foregoing, the Commission amends part 35, Chapter I, Title 18, of theEnd Amendment Part Start Part
PART 35—FILING OF RATE SCHEDULES AND TARIFFSEnd Part Start Amendment Part
1. The authority citation for part 35 continues to read as follows:End Amendment Part Start Amendment Part
2. In § 35.28, paragraph (g)(1)(iii) is revised as follows:End Amendment Part
(g) * * *
(1) * * *
(iii) Aggregation of retail customers. Each Commission-approved independent system operator and regional transmission organization must accept bids from an aggregator of retail customers that aggregates the demand response of the customers of utilities that distributed more than 4 million megawatt-hours in the previous fiscal year, and the customers of utilities that distributed 4 million megawatt-hours or less in the previous fiscal year, where the relevant electric retail regulatory authority permits such customers' demand response to be bid into organized markets by an aggregator of retail customers. An independent system operator or regional transmission organization must not accept bids from an aggregator of retail customers that aggregates the demand response of the customers of utilities that distributed more than 4 million megawatt-hours in the previous fiscal year, where the relevant electric retail regulatory authority prohibits such customers' demand response to be bid into organized markets by an aggregator of retail customers, or the customers of utilities that distributed 4 million megawatt-hours or less in the previous fiscal year, unless the relevant electric retail regulatory authority permits such customers' demand response to be bid into organized markets by an aggregator of retail customers.
The following statement will not appear in the Code of Federal Regulations.
KELLY, Commissioner, concurring in part and dissenting in part:
As I have noted in my separate statements at each phase of this proceeding, I continue to have misgivings about the potential impacts of several of Order No. 719's directives, including (1) the scarcity pricing measures; (2) the issue of promoting responsiveness of RTOs/ISOs by allowing them to adopt hybrid boards with stakeholder members; and (3) MMUs being removed from tariff administration and mitigation. Despite my ongoing concerns, I believe that some of these proposals have positively evolved over the course of this proceeding. A good deal of that evolution is due to the commenters who have taken the time to participate in our process, thereby moving the debate in a positive direction. I also want to commend Commission staff who have worked tirelessly on these efforts. I believe that the Commission has appropriately used Order No. 719 as a vehicle to move the issue of competition in organized markets in a generally positive direction. Further, as the order states, the Commission will continue to look for ways to strengthen organized markets.
Accordingly, I respectfully concur in part and dissent in part.
Suedeen G. KellyEnd Supplemental Information
1. Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, 73 FR 64,100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008) (Order No. 719 or Final Rule).Back to Citation
2. Organized market regions are areas of the country in which a regional transmission organization (RTO) or independent system operator (ISO) operates day-ahead and/or real-time energy markets. The following Commission-approved RTOs and ISOs have organized markets: PJM Interconnection, LLC (PJM); New York Independent System Operator, Inc. (NYISO); Midwest Independent Transmission System Operator, Inc. (Midwest ISO); ISO New England, Inc. (ISO New England); California Independent System Operator Corp. (CAISO); and Southwest Power Pool, Inc. (SPP).Back to Citation
3. In this rulemaking, the Commission also issued an advanced notice of proposed rulemaking, Wholesale Competition in Regions with Organized Electric Markets, Advance Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,617 (2007) (ANOPR) and a notice of proposed rulemaking, Wholesale Competition in Regions with Organized Electric Markets, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,628 (2008) (NOPR).Back to Citation
4. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 4, 15.Back to Citation
5. Id. P 274.Back to Citation
6. The use of the phrase “board of directors” herein also includes the board of managers, board of governors, and similar entities. An internal MMU in a hybrid structure may report to management so long as it does not perform any of the core MMU functions.Back to Citation
7. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 2.Back to Citation
8. Id. P 14.Back to Citation
9. Id. P 8, 578-83.Back to Citation
10. Additionally, Monitoring Analytics, LLC filed an out-of-time motion to intervene in this proceeding, but did not seek rehearing.Back to Citation
12. See, e.g., City of Campbell v. FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985) (“The 30-day time requirement of [the FPA] is as much a part of the jurisdictional threshold as the mandate to file for a rehearing.”); Boston Gas Co. v. FERC, 575 F.2d 975, 977-98, 979 (1st Cir. 1978) (describing identical rehearing provision of the Natural Gas Act as “a tightly structured and formal provision. Neither the Commission nor the courts are given any form of jurisdictional discretion.”).Back to Citation
13. See, e.g., Arkansas Power & Light Co., 19 FERC ¶ 61,115 at 61,217-18, reh'g denied, 20 FERC ¶ 61,013, at 61,034 (1982). See also Public Serv. Co. of New Hampshire, 56 FERC ¶ 61,105, at 61,403 (1991); CMS Midland, Inc., 56 FERC ¶ 61,177, at 61,623 (1991).Back to Citation
14. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 47.Back to Citation
15. Id. P 56.Back to Citation
16. Pennsylvania PUC at 4.Back to Citation
17. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 276.Back to Citation
18. Id. P 154.Back to Citation
19. Id. P 163.Back to Citation
20. See, e.g., TAPS at 9-13; Joint Petitioners at 18-23; NARUC at 3. NARUC states that it incorporates by reference the arguments presented on this issue by Joint Petitioners' request for rehearing. NARUC at 5.Back to Citation
22. TAPS at 11-12; Joint Petitioners at 18-19 (citing United States v. Public Utils. Comm'n of California, 345 U.S. 295, 303 (1953); Federal Power Comm'n v. Southern California Edison Co., 376 U.S. 202, 216 (1964)).Back to Citation
23. Joint Petitioners at 19.Back to Citation
24. TAPS at 12-13 (citing N.Y. v. FERC, 535 U.S. 1, 20 (2002); FPC v. Conway Corp., 426 U.S. 271, 276-77 (1976)).Back to Citation
25. Joint Petitioners at 13, 18 (citing Northern States Power Co., 176 F.3d 1090, 1096 (8th Cir. 1999), reh'g en banc denied 1999 U.S. App. LEXIS 23493 (8th Cir. Sept. 1, 1999), cert. denied sub nom.; Enron Power Mktg., Inc. v. Northern States Power Co., 528 U.S. 1182 (2000); Atlantic City Electric Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002)).Back to Citation
26. Section 532 of the Energy Independence and Security Act of 2007 amended PURPA section 111(d) by adding a new standard that requires consideration of rate design modifications to promote energy efficiency investments. 16 U.S.C. 2621(d). To assist in this effort, Joint Petitioners note that APPA and NRECA commissioned a reference manual regarding the new requirements. Reference Manual and Procedures for Implementation of the PURPA Standards in the Energy Independence and Security Act of 2007, Dr. Ken Rose and Michael Murphy, available at http://www.naruc.org/Publications/EISAStandardsManualFINAL.pdf. Joint Petitioners argue that efforts to have distribution cooperatives or public power distribution systems invest in a demand response program after considering these new federal PURPA standards could be undermined by the activities of third-party ARCs seeking to take the demand response of the public power or cooperative system's retail customers directly to the wholesale market. Joint Petitioners at 21.Back to Citation
27. 16 U.S.C. 824(f). Joint Petitioners at 21 (citing Bonneville Power Administration, et al. v. FERC, 422 F.3d 908, 915 (9th Cir. 2005).Back to Citation
28. Joint Petitioners state that the “Commission cannot bootstrap jurisdiction over * * * non-jurisdictional entities simply by pointing to jurisdiction over their retail customers” and that the Commission “cannot do indirectly what it cannot do directly.” Joint Petitioners at 21 (citing Richmond Power & Light v. FERC, 574 F.2d 610, 620 (D.C. Cir. 1978); Altamont Gas Transmission Co., et al. v. FERC, 92 F.3d 1239, 1248 (D.C. Cir. 1996); and Williams Gas Processing-Gulf Coast Co., L.P. v. FERC, 331 F.3d 1011, 1022 (D.C. Cir. 2003)).Back to Citation
29. Ohio PUC at 6-7 (stating that “it is the prerogative of each individual state commission to decide to what extent it will expose its retail customers to the wholesale market, and what, if any, advanced technology (i.e., smart meters) its retail customers desire and wish to purchase”).Back to Citation
30. Id. at 6. The Wisconsin PSC states that it adopts Ohio PUC's arguments on this issue. Wisconsin PSC at 2. NARUC states that it incorporates by reference the arguments presented on this issue by Ohio PUC's request for rehearing. NARUC at 5.Back to Citation
31. Joint Petitioners at 15-16.Back to Citation
32. Specifically, TAPS suggests that the Commission modify the regulatory text to replace: (1) The “unless” clause of 18 CFR 35.28(g)(1)(B)(3)(iii) with “if the relevant electric retail regulatory authority expressly permits a retail customer to participate”; and (2) the “unless” clause of 18 CFR 35.28(g)(1)(i)(A) with “if permitted by the laws or regulations of the relevant electric retail regulatory authority.” TAPS at 28.Back to Citation
33. Id. at 31. TAPS notes that under Order No. 890, network customers must attest, for each network resource identified for designation, that: (1) The transmission customer owns or has committed to purchase the designated network resource; and (2) the designated network resource meets the requirements for designated network resources. Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC ¶ 61,299 (2008).Back to Citation
34. AEP at 1.Back to Citation
35. Id. at 2.Back to Citation
36. Id. at 2-3.Back to Citation
37. NARUC states that it incorporates by reference the arguments presented on this issue by Joint Petitioners' request for rehearing. NARUC at 5.Back to Citation
38. TAPS at 25-26.Back to Citation
39. For example, Joint Petitioners note that CMUA explained in its NOPR comments that the presumption of implicit authority to allow ARCs to aggregate bids makes no sense in California because direct access was suspended following the 2000-01 market crisis. Accordingly, California no longer has laws or regulations dealing with new direct access, and CMUA has not restructured its retail rules and ordinances with retail choice as an option. Therefore, Joint Petitioners state that to now require an affirmative action would be a substantial undertaking. Joint Petitioners at 16-17.Back to Citation
40. TAPS notes that its members include: (1) AMP-Ohio, serving 123 municipal electric systems in Midwest ISO and PJM; (2) Indiana Municipal Power Agency, serving 51 municipal electric systems in Midwest ISO and PJM; and (3) Wisconsin Public Power, serving 50 municipal electric systems in Midwest ISO. TAPS at 26.Back to Citation
42. Joint Petitioners at 23.Back to Citation
43. TAPS at 26-27.Back to Citation
44. American Trucking Ass'ns v. EPA, 175 F.3d 1027, 1044 (DC Cir. 1999), aff'd in part and rev'd in part sub nom. Whitman v. American Trucking Ass'ns, 531 U.S. 457 (2001).Back to Citation
45. TAPS at 28. TAPS states that the Final Rule “requires [load-serving entities] to either: (1) Invest in the legislative and/or regulatory procedures necessary to obtain an explicit `out' and enforce it; * * * or (2) undertake the implementation burdens necessary to accommodate ARCs and retail customers directly bidding retail demand response into wholesale markets.” Id.Back to Citation
46. Id. at 29.Back to Citation
47. Joint Petitioners at 27. In its NOPR comments, APPA suggested an alternative approach of differentiating public power systems by their size. Under this alternative, the relevant electric retail regulatory authorities governing public power systems that are located in the RTO or ISO regions and larger than the RFA size requirement (i.e., 4 million MWh or more in total output in one year) would have to consider the issue of third-party ARCs and aggregation of their retail customers, if they had not already done so. They would have the affirmative requirement to inform their RTO or ISO whether their local election was not to permit the aggregation by ARCs on their public power systems, or permit it only under enumerated conditions in order to preclude third-party bidding of their consumers' loads. APPA NOPR Comments at 47-48.Back to Citation
48. Joint Petitioners at 28-29.Back to Citation
49. TAPS at 30.Back to Citation
50. Id. at 14 (citing TAPS NOPR Comments at 13-17).Back to Citation
51. Id. at 14-15.Back to Citation
52. Id.Back to Citation
53. Joint Petitioners at 14-15.Back to Citation
54. Id. at 15.Back to Citation
55. TAPS at 17.Back to Citation
56. Id. at 18.Back to Citation
57. TAPS provides the following example to explain “phantom energy”:
[I]f a [transmission-dependent entity] with 100 MW of metered load in a given hour has a retail customer that has sold 5 MW of demand response energy into the RTO's energy imbalance market in that same hour, then to avoid double-counting the demand response that is already reflected in the [load-serving entity's] metered load, the RTO would charge the [load-serving entity] for 105 MWh of energy—i.e. as if the 5 MWh of demand response energy had been purchased by the [load-serving entity], delivered to the retail customer, and then re-sold. Id. at 19-20.Back to Citation
58. Id. at 22. TAPS notes that such a deviation charge may not apply during an emergency, as provided elsewhere in Order No. 719.Back to Citation
59. Id. (citing Southwest Power Pool, FERC Electric Tariff, Fifth Revised Volume No. 1, Attachment AE, sections 5.3 and 5.4).Back to Citation
60. Id.Back to Citation
61. Id. at 22-23.Back to Citation
62. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 594; NOPR, FERC Stats. & Regs. ¶ 32,628 at P 83.Back to Citation
64. Section 205(a) of the FPA charges the Commission with ensuring that rates and charges for jurisdictional sales by public utilities and “all rules and regulations affecting or pertaining to such rates or charges” are just and reasonable. Id. 824d(a). Section 206(a) gives the Commission authority over rate and charges by public utilities for jurisdictional sales as well as “any rule, regulation, practice or contract affecting such rates and charges” to make sure that they are just and reasonable and not unduly discriminatory or preferential. Id. 824e(a).Back to Citation
65. In Order No. 890, the Commission found that sales of ancillary services by “load services. * * * should be permitted where appropriate on a comparable basis to service provided by generation resources.” Order No. 890, FERC Stats. & Regs. ¶ 31,241 (2007).Back to Citation
66. See, e.g., City of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985) (“[T]here is an infinitude of practices affecting rates and service. * * * It is obviously left to the Commission, within broad bounds of discretion, to give concrete application to this amorphous directive.”).Back to Citation
67. Connecticut Dep't of Public Util. Control v. FERC, No. 07-1375, slip op. at 14-15 (D.C. Cir. June 23, 2009).Back to Citation
68. Id. at 15. The court further stated that “[w]here capacity decisions about an interconnected bulk power system affect [Commission]-jurisdictional transmission rates for that system * * * they come within the Commission's authority,” adding that “there is nothing special about capacity decisions that places them beyond the Commission's jurisdiction”. Id. at 14-15.Back to Citation
69. See, e.g., PJM Interconnection, LLC, 117 FERC ¶ 61,331 (2006); Devon Power L.L.C., 115 FERC ¶ 61,340, order on reh'g, 117 FERC ¶ 61,133 (2006).Back to Citation
70. See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ¶ 61,136 (2001); NSTAR Services Co. v. New England Power Pool, 95 FERC ¶ 61,250 (2001); New England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287, order on reh'g, 101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 105 FERC ¶ 61,211 (2003); PJM Interconnection, LLC, 99 FERC ¶ 61,139 (2002).Back to Citation
71. See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ¶ 61,223 (2001); New England Power Pool and ISO New England, Inc., 100 FERC ¶ 61,287, order on reh'g, 101 FERC ¶ 61,344 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 105 FERC ¶ 61,211 (2003); PJM Interconnection, LLC, 99 FERC ¶ 61,227 (2002).Back to Citation
72. ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 37.Back to Citation
73. NOPR, FERC Stats. & Regs. ¶ 32,628 at P 29.Back to Citation
74. Id. P 30. Increasing the presence of demand response also provides market participants with better information about where they should and should not construct upgrades. “In current market contexts, constructing new generation facilities in response to a higher [installed capacity requirement] may even feel like an imperative. But petitioners have posited no source for that feeling other than internalization of the true costs of the alternatives, which is not only a requirement for efficient market outcomes, but, again, something the Commission may concededly pursue.” Connecticut Dep't of Public Util. Control v. FERC, No. 07-1375, slip op. at 11 (D.C. Cir. June 23, 2009).Back to Citation
75. NOPR, FERC Stats. & Regs. ¶ 32,628 at P 31.Back to Citation
76. For example, “[b]y reducing electricity demand at critical times (e.g., when a generator or a transmission line unexpectedly fails), demand response that is dispatched by the system operator on short notice can help return electric system (or localized) reserves to pre-contingency levels.” Federal Energy Regulatory Commission, Assessment of Demand Response and Advanced Metering: Staff Report, Docket No. AD06-2-000, at 11 (Aug. 2006) (2006 FERC Staff Demand Response Assessment); see also Federal Energy Regulatory Commission, Assessment of Demand Response and Advanced Metering: Staff Report, at 50-53 (Dec. 2008) (describing the use of demand response during system emergencies in 2007 to ensure system reliability).Back to Citation
77. Where a provision or term directly affects a wholesale rate, it is within the Commission's jurisdiction. See, e.g., Connecticut Dep't of Public Util. Control v. FERC, No. 07-1375, slip op. at 10 (D.C. Cir. June 23, 2009) (finding that the Commission has jurisdiction to directly or indirectly establish prices for capacity even for the purposes of incentivizing construction of new generation facilities); Mississippi Industries v. FERC, 808 F.2d 1525 (D.C. Cir. 1987), vacated in part on other grounds, 822 F.2d 1103 (D.C. Cir. 1987) (holding that the Commission had jurisdiction over the allocation of a nuclear plant's capacity and costs because it “directly affects costs and, consequently, wholesale rates.”); Municipalities of Groton v. FERC, 587 F.2d 1296, (D.C. Cir. 1978); Cal. Indep. Sys. Operator Corp., 119 FERC ¶ 61,076, at P 540-56 (2007) (finding that maintaining adequate resources falls within Commission jurisdiction because it has a direct and significant effect on wholesale rates and services); ISO New England, Inc., 119 FERC ¶ 61,161, at P 18-30 (2007) (same).Back to Citation
78. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 3; NOPR, FERC Stats. & Regs. ¶ 32,628 at P 282.Back to Citation
79. 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. See 5 U.S.C. 601(3), citing to 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 utility as one that, including its affiliates is primarily engaged in the generation, transmission, or distribution of electric energy for sale, and whose total electric output for the preceding fiscal year did not exceed 4 million MWh. 13 CFR 121.202 (Sector 22, Utilities, North American Industry Classification System (NAICS)) (2004).Back to Citation
80. Open Access Same-Time Information System and Standards of Conduct, Order No. 889, FERC Stats. & Regs. ¶ 31,035, clarified, 77 FERC ¶ 61,253 (1996), order on reh'g, Order No. 889-A, FERC Stats. & Regs. ¶ 31,049, reh'g denied, Order No. 889-B, 81 FERC ¶ 61,253 (1997), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2006).Back to Citation
81. See Wolverine Power Supply Coop., 127 FERC ¶ 61,159, at P 15 (2009).Back to Citation
82. See San Diego Gas & Elec. Co. v. Sellers of Energy and Ancillary Services in Markets Operated by the CAISO, 125 FERC ¶ 61,297, at P 24 (2008).Back to Citation
85. In the Final Rule, the Commission allowed RTOs and ISOs to specify certain requirements for an ARC's bids, including certification that participation is not precluded by the relevant electric retail regulatory authority. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 158g.Back to Citation
86. EPAct 2005, section 1252(f) (emphasis added).Back to Citation
87. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 155.Back to Citation
88. NOPR, FERC Stats. & Regs. ¶ 32,628 at P 291.Back to Citation
89. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 155, 602.Back to Citation
90. See discussion supra P 51.Back to Citation
92. Mid-Tex Electric Corp., Inc. v. FERC, 773 F.2d 327, 342 (D.C. Cir. 1985) (Mid-Tex) (“Congress did not intend to require that every agency consider every indirect effect that any regulation might have on small businesses in any stratum of the national economy”).Back to Citation
93. American Trucking Associations, 175 F.3d at 1044.Back to Citation
94. Id. at 1044 (“Only if a [s]tate does not submit a [state implementation plan] that complies with [EPA's rule], must the EPA adopt an implementation plan of its own, which would require the EPA to decide what burdens small entities should bear”).Back to Citation
95. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 154.Back to Citation
96. The Final Rule provided regional flexibility for each RTO and ISO to work with its stakeholders in proposing market rules appropriate for its region. Id. P 155. Interested parties could participate in that stakeholder process. By filing comments on the RTO's or ISO's subsequent compliance filing, interested parties had an additional opportunity to address the Commission directly on any remaining concerns with the RTO's or ISO's implementation proposal. The Commission will address the merits of such implementation issues on a case-by-case basis.Back to Citation
97. TAPS requested, among other things, that we direct the RTO or ISO to provide certain detailed information in real-time to affected load-serving entities. TAPS has failed to demonstrate the need for such data in real-time.Back to Citation
98. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 159.Back to Citation
99. Id. P 192.Back to Citation
100. Id.Back to Citation
101. Id. P 194.Back to Citation
102. The four approaches are: (1) RTOs and ISOs would increase the energy supply and demand bid caps above the current levels only during an emergency; (2) RTOs and ISOs would increase bid caps above the current level during an emergency only for demand bids while keeping generation bid caps in place; (3) RTOs and ISOs would establish a demand curve for operating reserves, which has the effect of raising prices in a previously agreed-upon way as operating reserves grow short; and (4) RTOs and ISOs would set the market-clearing price during an emergency for all supply and demand response resources dispatched equal to the payment made to participants in an emergency demand response program. Id. P 208.Back to Citation
103. The six criteria are: (1) Improve reliability by reducing demand and increasing supply during periods of operating reserve shortages; (2) make it more worthwhile for customers to invest in demand response technologies; (3) encourage existing generation and demand resources to continue to be relied upon during an operating reserve shortage; (4) encourage entry of new generation and demand resources; (5) ensure that the principle of comparability in treatment of and compensation to all resources is not discarded during periods of operating reserve shortage; and (6) ensure market power is mitigated and gaming behavior is deterred during periods of operating reserve shortages including, but not limited to, showing how demand resources discipline bidding behavior to competitive levels. Id. P 246-47.Back to Citation
104. Joint Petitioners at 32-33.Back to Citation
105. Id. at 44 (citing NRECA Affidavit at P 20-55).Back to Citation
106. TAPS at 33 (citing TAPS NOPR Comments at 24-27).Back to Citation
107. Id. at 39.Back to Citation
108. For example, SMUD explains that in NYISO, the Commission imposed a bid cap based on its finding that the NYISO market lacks demand-side responsiveness to prices and that it has tight supplies. Id. at 5. (citing New York Indep. System Operator, 97 FERC ¶ 61,154, at 61,673 (2001)). SMUD also adds that the Commission previously found that price caps are necessary to prevent opportunistic pricing during periods of capacity shortages and that bid caps provide a safety net to contain prices in peak periods when supply is short. SMUD at 4. (citing ISO New England, Inc., 97 FERC ¶ 61,090, at 62,469, 61,470-471 (2001)).Back to Citation
109. Id. at 4. (citing Nstar Serv. Co. v. New England Power Pool, 92 FERC ¶ 61,065, at 62,198-99 (2000)).Back to Citation
110. Joint Petitioners at 41.Back to Citation
111. Industrial Coalition at 7-8.Back to Citation
112. Pennsylvania PUC at 5.Back to Citation
113. Joint Petitioners at 48-49.Back to Citation
114. Old Dominion at 4.Back to Citation
115. Id. at 5-6.Back to Citation
116. Ohio PUC at 7.Back to Citation
117. They note that the Commission never addressed APPA's request for full evidentiary hearings. Id. at 49 (citing APPA NOPR Comments at 54-55, 62, 64).Back to Citation
118. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 251.Back to Citation
119. TAPS at 54-56.Back to Citation
120. Id. at 42-45.Back to Citation
121. Joint Petitioners at 35 (citing Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 235).Back to Citation
122. Id. at 41.Back to Citation
123. Id. at 49-50 (citing NRECA NOPR Comments at 29).Back to Citation
124. TAPS states that the Final Rule's regulatory text language in section 35.28(g)(1)(iv)(A) would preclude an RTO or ISO from proposing the NRECA approach or any other beneficial demand response program. Thus, it requests the following modifications:
Commission-approved ISOs and RTOs must modify their market rules to allow (1) the market-clearing price during periods of operating reserve shortage to reach a level that rebalances supply and demand or (2) payments to demand response resources. In either case, the rules must [so as to] maintain reliability while providing sufficient provisions for mitigating market power.
TAPS at 48 (citing TAPS NOPR Comments at 3).Back to Citation
125. Joint Petitioners at 42.Back to Citation
126. Id. at 51-52.Back to Citation
127. Id. at 53.Back to Citation
128. Id. at 49.Back to Citation
129. Id. at 53 (citing United States Government Accountability Office, Report to the Committee on Homeland Security and Governmental Affairs, U.S. Senate, Electricity Restructuring: FERC Could Take Additional Steps to Analyze Regional Transmission Organizations' Benefits and Performance (Sept. 2008), available at http://www.gao.gov/new.items/d08987.pdf) (2008 GAO Report)).Back to Citation
130. Joint Petitioners at 54.Back to Citation
131. The Commission held three technical conferences in 2007 to gather information and address issues on competition at the wholesale level and other related issues. See NOPR, FERC Stats. & Regs. ¶ 32,628 at P 2.Back to Citation
132. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 192; NOPR, FERC Stats. & Regs. ¶ 32,628 at P 107.Back to Citation
133. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 192.Back to Citation
134. Id. P 195.Back to Citation
135. Id. P 235.Back to Citation
136. Id. P 187 (citing PJM Power Providers NOPR Comments at 3).Back to Citation
137. For example, a critical peak pricing experiment in California in 2004 determined that small residential and commercial customers are price responsive and will produce significant demand reductions. Participants in the California peak pricing experiment reduced demand by 13 percent on average and by as much as 27 percent when price signals were coupled with automated controls, such as controllable thermostats. 2006 FERC Staff Demand Response Assessment at 13.Back to Citation
138. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 196.Back to Citation
139. Id. P 251.Back to Citation
140. Id. P 247.Back to Citation
141. Id. P 235.Back to Citation
142. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194-95.Back to Citation
143. Id. P 195.Back to Citation
144. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 239, 249-50.Back to Citation
145. Id. P 249.Back to Citation
146. Id. P 244.Back to Citation
147. Id. P 196.Back to Citation
148. Id. P 307.Back to Citation
149. Id.Back to Citation
150. SMUD at 7.Back to Citation
151. Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, FERC Stats. & Regs. ¶ 31,226, order on reh'g, Order No. 681-A, 117 FERC ¶ 61,201 (2006).Back to Citation
152. Order No. 681-A, 117 FERC ¶ 61,201 at P 105.Back to Citation
153. Cal. Indep. Sys. Operator Corp., 120 FERC ¶ 61,023, at P 229 (2007), reh'g denied, 124 FERC ¶ 61,094 (2008).Back to Citation
154. Id.Back to Citation
155. Order No. 681-A, 117 FERC ¶ 61,201 at P 106.Back to Citation
156. Supplemental Notice of Technical Conference, Capacity Markets in Regions with Organized Electric Markets, Docket No. AD08-4-000 (April 25, 2008).Back to Citation
157. APPA-CMUA at 3.Back to Citation
158. Id. at 21.Back to Citation
159. Id. at 25 (citing Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 686-87 (D.C. Cir. 2000); Associated Gas Distribs. v. FERC, 824 F.2d 981, 1008 (D.C. Cir. 1987)).Back to Citation
160. Id. at 26 (citing Order No. 2000, FERC Stats & Regs at 31,043 n.163).Back to Citation
161. 549 U.S. 497 (2008).Back to Citation
162. APPA-CMUA at 28.Back to Citation
163. Id. at 32 (citing 2008 GAO Report). See supra note 129.Back to Citation
164. Id. at 34-36.Back to Citation
165. See Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-845 (1984).Back to Citation
166. See Massachusetts v. EPA, 549 U.S. at 527.Back to Citation
167. Id. at 530.Back to Citation
168. See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 13.Back to Citation
169. Id. P 2; NOPR, FERC Stats. & Regs. ¶ 32,628 at P 4, 282.Back to Citation
170. See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 280.Back to Citation
171. For instance, the Commission recently held a technical conference on credit issues affecting the electric power industry. Technical Conference on Credit and Capital Issues Affecting the Electricity Power Industry, Docket No. AD09-2-000 (Jan. 13, 2009).Back to Citation
172. NOPR, FERC Stats. & Regs. ¶ 32,628 at P 16-25.Back to Citation
174. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 317 et seq.Back to Citation
175. Id. P 395 et seq.Back to Citation
176. A hybrid MMU structure is one with both an internal and an external market monitor. An internal market monitor is one that is composed of RTO or ISO employees, an external market monitor is an independent entity that conducts market monitoring for the RTO or ISO pursuant to a contract.Back to Citation
177. Old Dominion at 6-7.Back to Citation
178. Pennsylvania PUC at 5-6.Back to Citation
179. Id. at 3.Back to Citation
180. Industrial Coalitions at 12-14.Back to Citation
181. Ohio PUC at 14-15; Wisconsin PSC at 2-3.Back to Citation
182. Ohio PUC at 15.Back to Citation
183. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 370-79.Back to Citation
184. Pennsylvania PUC at 3.Back to Citation
185. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 374.Back to Citation
186. Ohio PUC at 13.Back to Citation
187. Id. at 13-16.Back to Citation
188. Id. at 16-17.Back to Citation
189. Id. at 14. We assume here that “existing MMU” means an external MMU.Back to Citation
190. Wisconsin PSC at 2-3.Back to Citation
191. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 327.Back to Citation
192. Id. P 446-59.Back to Citation
193. Illinois Commerce Commission at 4-5.Back to Citation
194. Id.Back to Citation
195. Id. at 2-4.Back to Citation
196. Minnesota PUC at 1.Back to Citation
197. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 446-59.Back to Citation
198. State commissions have the further safety valve of seeking otherwise proscribed information by filing a request with the Commission. Id. P 458.Back to Citation
199. Id. P 452.Back to Citation
200. Id. P 450.Back to Citation
201. Id. P 465.Back to Citation
202. Most RTOs and ISOs have a six-month release policy.Back to Citation
203. TAPS at 56.Back to Citation
204. Id. at 57.Back to Citation
205. Id. at 58.Back to Citation
206. Id. at 59.Back to Citation
207. Id. at 60.Back to Citation
208. “System lambda” is defined as the variable cost of the last kilowatt produced over a particular hour. APPA-CMUA at 39.Back to Citation
209. Id. at 15-16.Back to Citation
210. Id. at 37-38.Back to Citation
211. Id. at 38.Back to Citation
212. Id. at 39.Back to Citation
213. Illinois Commerce Commission at 8.Back to Citation
214. Id. at 7.Back to Citation
215. Minnesota PUC at 1.Back to Citation
216. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 424.Back to Citation
217. The fact that ISO-NE proposed reducing the lag time for release of offer and bid data from six months to three months is evidence of the fact that the stakeholder process is not necessarily geared toward less disclosure. See ISO New England Inc. and New England Power Pool, 121 FERC ¶ 61,035 (2007).Back to Citation
218. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 423.Back to Citation
219. Id. P 383-87.Back to Citation
220. Id. P 385.Back to Citation
221. Potomac Economics at 1.Back to Citation
222. Id.Back to Citation
223. Id. at 6-7.Back to Citation
224. Id. at 2.Back to Citation
225. Id. at 3.Back to Citation
226. Id. at 5.Back to Citation
227. Id.Back to Citation
228. The purpose of this holding is to prevent potential conflicts of interest that arise when the MMU oversees its own actions. Thus, if an MMU wants to enter into a contract to oversee the activities of a market participant that operates wholly outside of the RTO or ISO the MMU oversees, the conditions in this order would not apply. Likewise, if an MMU wants to enter into a contract with a market participant that has activity inside and outside of an RTO or ISO the MMU oversees, and the MMU would only oversee the market participant's activity outside of that RTO or ISO, the conditions in this order would not apply.Back to Citation
229. Market Monitoring Units in Regional Transmission Organizations and Independent System Operators, 111 FERC ¶ 61,267 (2005).Back to Citation
230. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 556-57.Back to Citation
231. Id. P 515.Back to Citation
232. APPA-CMUA at 41 (citing APPA NOPR Comments at 97-103).Back to Citation
233. Id. at 40-43.Back to Citation
234. TAPS at 67 (citing 2008 GAO Report). See supra note 129.Back to Citation
235. TAPS at 67.Back to Citation
236. SMUD at 9.Back to Citation
237. Id. at 11.Back to Citation
238. Pennsylvania PUC at 7.Back to Citation
239. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 505.Back to Citation
240. Id. P 515. See also discussion supra P 71 (declining to require cost-benefit analysis for ARCs' participation in RTO- and ISO-administered markets but encouraging RTOs and ISOs to evaluate this option individually).Back to Citation
241. See infra, note 254.Back to Citation
242. See Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395 (D.C. Cir. 2004).Back to Citation
243. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 534.Back to Citation
244. Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999), order on reh'g, Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000), aff'd sub nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).Back to Citation
245. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 537 (citing Order No. 2000, FERC Stats. & Regs. 31,089 at 31,073-75).Back to Citation
246. Id.Back to Citation
247. Illinois Commerce Commission at 9.Back to Citation
248. 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, FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, 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).Back to Citation
249. Pennsylvania PUC at 9.Back to Citation
250. Industrial Coalitions at 17.Back to Citation
251. Ohio PUC at 19; Wisconsin PSC at 3.Back to Citation
252. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 534-37.Back to Citation
253. Id. P 537.Back to Citation
254. Indeed, some state regulators may be prohibited by state law from serving on the boards of public utilities, and an RTO or ISO covering one state or a small number of states may be unable to meet such a generic membership requirement. We further note that requiring that any particular class of stakeholders, including state regulators, have membership on RTO and ISO boards is a slippery slope; we do not wish to impose any affirmative requirements for category of board members.Back to Citation
255. Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 556.Back to Citation
256. APPA at 44-45.Back to Citation
257. TAPS at 60-62.Back to Citation
1. See Wholesale Competition in Regions with Organized Electric Markets, Advance Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,617 (2007), Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,628 (2008), Order No. 719, 73 FR 61,400 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008) (Comm'r Kelly concurring in part and dissenting in part).Back to Citation
[FR Doc. E9-17364 Filed 7-28-09; 8:45 am]
BILLING CODE 6717-01-P