2011-27626. Enhancement of Electricity Market Surveillance and Analysis Through Ongoing Electronic Delivery of Data From Regional Transmission Organizations and Independent System Operators

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Notice of proposed rulemaking.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) proposes to revise its regulations to require each regional transmission organization (RTO) and independent system operator (ISO) to electronically deliver to the Commission, on an ongoing basis, data related to the markets that it administers. Ongoing electronic delivery of data relating to physical and virtual offers and bids, market awards, resource outputs, marginal cost estimates, shift factors, financial transmission rights, internal bilateral contracts, and interchange pricing will facilitate the Commission's development and evaluation of its policies and regulations and will enhance Commission efforts to detect anti-competitive or manipulative behavior, or ineffective market rules, thereby helping to ensure just and reasonable rates.

DATES:

Comments on the proposed rule are due December 27, 2011.

Comments, identified by docket number, may be filed in the following ways:

• Electronic Filing through http://www.ferc.gov. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format.
• Mail/Hand Delivery: Those unable to file electronically may mail or hand-deliver comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street, NE., Washington, DC 20426.

Instructions: For detailed instructions on submitting comments and additional information on the rulemaking process, see the Comment Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT:

William Sauer (Technical Information), Office of Enforcement, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone], [e-mail].

Christopher Daignault (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone], [e-mail].

SUPPLEMENTARY INFORMATION:

Notice of Proposed Rulemaking

October 20, 2011.

1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) proposes, pursuant to sections 301(b) and 307(a) of the Federal Power Act (FPA),^[1] to amend its regulations to require each regional transmission organization (RTO) and independent system operator (ISO) to electronically deliver to the Commission, on an ongoing basis, data related to the markets that it administers. Ongoing electronic delivery of data relating to physical and virtual offers and bids, market awards, resource outputs, marginal cost estimates, shift factors, financial transmission rights (FTR), internal bilateral contracts, and interchange pricing will facilitate the Commission's development and evaluation of its policies and regulations and will enhance Commission efforts to detect anti-competitive or manipulative behavior, or ineffective market rules, thereby helping to ensure just and reasonable rates.

I. Background

2. Wholesale electricity markets have witnessed tremendous change in recent years. In the decades after the 1935 enactment of the FPA, the industry was characterized by self-sufficient, vertically integrated utilities. Most utilities built their own generation, transmission, and distribution facilities and sold electricity to their own wholesale and retail customers. During this time, the Commission regulated jurisdictional entities' rates through traditional cost-based ratemaking. Cost-based rate regulation ensures that rates are just and reasonable by administratively determining an entity's cost of providing service. Changes in national policy and other forces led to increased coordination and competition in the late 1960s and 1970s,^[2] and the enactment of the Public Utility Regulatory Policies Act (PURPA).^[3] The 1980s and early 1990s experienced an increased adoption of market-based ratemaking and wholesale power sales competition to promote efficiency and to lower wholesale power prices.^[4]

3. National policy fostered further market evolution by encouraging increased competition among generators through the Energy Policy Act of 1992 (EPAct 1992).^[5] Specifically, EPAct 1992 eased regulatory restrictions so that independent and affiliate generators could more easily enter, and compete in, wholesale electricity markets. EPAct 1992 also expanded the Commission's authority to address undue discrimination in transmission access in order to promote wholesale competition. In subsequent orders, the Commission found that the availability of transmission service enhances competition in power markets, by increasing power supply options of buyers and power sales options of sellers, and leads to lower rates for consumers.^[6] By the mid-1990s, the Commission had determined that additional measures were needed to address undue discrimination in transmission access and issued Order Nos. 888^[7] and 889,^[8] which required “open access” transmission service. In doing so, the Commission explained that its action “remove[s] impediments to competition in the wholesale power marketplace and * * * bring[s] more efficient, lower cost power to the Nation's electricity customers.” ^[9] The Commission subsequently issued Order No. 890,^[10] to further remedy undue discrimination and thereby remove barriers to competition.

4. In addition to addressing undue discrimination in transmission access, Order No. 888 encouraged the formation of ISOs. The Commission posited that “ISOs have great potential to assist us and the industry to help provide regional efficiencies, to facilitate economically efficient pricing, and, especially in the context of power pools, to remedy undue discrimination and mitigate market power.” ^[11] To facilitate ISO formation and foster independent operation of the transmission grid, the Commission suggested that utilities should voluntarily transfer operating control of their transmission facilities to an ISO. Four years later, in Order No. 2000,^[12] the Commission encouraged the voluntary formation of RTOs to administer the transmission grid on a regional basis. To date, the Commission has approved six RTOs and ISOs: PJM Interconnection, L.L.C. (PJM); New York Independent System Operator, Inc. (NYISO); Midwest Independent Transmission System Operator, Inc. (Midwest ISO); ISO New England Inc. (ISO-NE); California Independent System Operator Corporation (CAISO); and Southwest Power Pool, Inc. (SPP). Together, these six RTOs and ISOs serve more than half of the United States' wholesale electricity demand.^[13]

5. The wholesale electricity markets operated by Commission-approved RTOs/ISOs have evolved since their inception and will likely continue to do so as advances in technology usher in additional competing resources, computational efficiencies, new products, and new types of market participants. Today, for example, market participants include independent generating resources, storage devices, demand response and energy efficiency providers, marketers and traders, vertically integrated utilities, power marketing administrations, municipalities and cooperatives, among others.

6. Substantial changes also have occurred with respect to the manner in which electricity is bought and sold. For example, when the IntercontinentalExchange (ICE) was established in 2000, the vast majority of electricity sales transacted on ICE contained requirements for physical delivery. Electricity bought or sold without requirements for physical delivery is commonly referred to as a financial electricity product. Beginning in 2004, the volume of financial electricity products bought and sold on ICE eclipsed that of electricity bought and sold on ICE with physical delivery requirements. The financial electricity product volumes on ICE also surpassed electricity volumes reported to the Commission through Electric Quarterly Reports (EQR) in several markets.^[14] Given that financial electricity products commonly settle using published prices from Commission-jurisdictional markets, changes in the prices of physical electricity products impact the values of both physical and financial electricity products.

7. Recognizing the importance of information relating to market trading and market oversight, the Commission issued Order No. 2001 ^[15] and Order No. 697,^[16] establishing reporting requirements for entities selling under market-based rates. As one keen observer stated, in this regard, “[i]nformation is the key to a viable electricity market and to preventing market manipulation.” ^[17] In addition, the Energy Policy Act of 2005 (EPAct 2005) ^[18] gave the Commission expanded authority to address market manipulation,^[19] including the ability to assess civil fines and seek criminal penalties.^[20]

8. Independent market monitoring by RTO/ISO market monitoring units (MMU) is an important means to evaluate market developments and to identify and deter market abuses and manipulation. In Order No. 2000, the Commission identified market monitoring as a basic function of an RTO.^[21] The Commission refined its approach to MMUs in a 2005 policy statement and in Order No. 719.^[22] In the 2005 Policy Statement, the Commission outlined tasks for MMUs to perform in order to enhance the competitive structure of RTO/ISO markets.^[23] Subsequently, in Order No. 719, the Commission further clarified requirements for MMU functions, independence, and information sharing.^[24]

9. The Commission has acknowledged that MMUs perform a vital and necessary function in market oversight ^[25] but that they do not supplant the Commission's authority.^[26] Rather, MMUs are designed to provide the Commission with an additional means of detecting market power abuses, market design flaws, and opportunities for improvements in market efficiency.^[27]

II. Discussion

10. In this NOPR, the Commission proposes to revise its regulations to require each RTO and ISO to electronically deliver to the Commission, on an ongoing, non-public basis, data related to the markets that it administers; namely, data relating to physical and virtual offers and bids, market awards, resource outputs, marginal cost estimates, shift factors, FTRs, internal bilateral contracts, and interchange pricing. To facilitate such ongoing, electronic delivery, the Commission proposes that each RTO and ISO use automated electronic procedures to provide this data.

11. The Commission is statutorily obligated to ensure that sales of electricity in wholesale markets are made at just and reasonable rates,^[28] and to address market manipulation in connection with the purchase or sale of electricity subject to the Commission's jurisdiction.^[29] Toward that end, section 301(b) of the FPA provides that the Commission shall at all times have access to and the right to inspect and examine all accounts and records of public utilities.^[30] In this NOPR, and pursuant to its authority under section 301(b), the Commission proposes to seek ongoing electronic delivery of data including accounts and records of the RTOs/ISOs, which are public utilities.

12. Moreover, the Commission also has authority pursuant to section 307(a) of the FPA to investigate any facts, conditions, practices, or matters it may deem necessary or proper to determine whether any person, electric utility, transmitting utility, or other entity may have violated or might violate the FPA or the Commission's regulations, or to aid in the enforcement of the FPA or the Commission regulations, or to obtain information about wholesale power sales or the transmission of power in interstate commerce.^[31]

13. As markets continue to evolve with increased levels of sophistication, the Commission must continue to evaluate the type of data necessary to ensure just and reasonable rates. The Commission's market monitoring and surveillance capabilities and associated data requirements must keep pace with market developments and evolve along with the markets. Further, the Commission's evaluation of the market rules, regulations, and policies should be informed by the data collection proposed herein. Electronic delivery of the types of data proposed herein will help to bring the Commission's access to RTO/ISO data in sync with the types and levels of activity in those markets and help to ensure that rates are just and reasonable.

14. Most of the data discussed in this NOPR are already collected and stored by the RTOs/ISOs in order to administer their markets. To the extent that an RTO/ISO does not already collect specific data, the Commission is not proposing to require either the collection of such data from market participants or its electronic delivery to the Commission. The Commission also proposes that key identifiers and other descriptive details necessary to understand the data be included in the data electronically delivered to the Commission. Finally, the Commission proposes that each RTO/ISO electronically deliver the data to the Commission using a common transfer method and format (i.e., Secure File Transfer Protocol and XML), which are described below. The Commission is not proposing that each RTO/ISO aggregate or materially modify the data prior to electronic delivery to the Commission.^[32]

15. This NOPR proposes to require an automated data delivery process, in part, to minimize any burden on RTOs/ISOs. The Commission currently can request this data from individual RTOs and ISOs on an ad hoc basis. Such recurrent, periodic data requests may require more Commission and RTO/ISO resources than the proposed electronic delivery of this data using an automated process.

16. Although the six RTOs/ISOs have developed different wholesale electricity market designs, there are many similarities in the data that they use to administer these markets. Generally speaking, market participants with their own supply resources or with supply resources under contract submit energy supply offers indicating the price at which they are willing to supply various quantities of energy. Load-serving entities submit demand bids indicating the price at which they are willing to buy various quantities of energy. The supply offers pass through market power screens. These screens are used to determine whether the resources can affect the market price and whether the offers should be mitigated. If an energy supply offer triggers the application of mitigation, it is replaced with a mitigated energy supply offer. Generally, mitigated energy supply offers are calculated using estimated marginal cost data, which approximate generators' costs under different conditions.^[33]

17. Similar to the process for submitting energy offers and bids, market participants with their own supply resources or with supply resources under contract also submit offers to provide ancillary services and capacity services.^[34] These offers typically indicate a price at which a market participant is willing to provide the service and, like the energy supply offers discussed above, are subject to mitigation when appropriate.

18. Entities with or without physical assets or load obligations may also submit “virtual” supply offers and demand bids in the RTO/ISO day-ahead markets. These virtual offers and bids contribute to price formation in RTO/ISO markets. Further, entities located outside of the RTO/ISO footprint may submit supply offers and demand bids in the form of interchange offers and bids.

19. The RTOs/ISOs match the above-described inputs through an intricate process designed to use the lowest-cost resources to meet demand.^[35] This process yields pricing signals through locational marginal pricing (LMP) that determine which supply offers and demand bids are selected (and which would also inform long-term planning, e.g., decisions on whether to enter and exit markets). Supply offers that are selected are required to provide a specific amount of service. For example, resources that are selected in the day-ahead energy market will be given an energy market award that specifies the amount of energy a particular resource is financially obligated to supply. These market awards are determined by each resource's supply offer and the corresponding day-ahead LMP. Finally, the RTO/ISO provides dispatch instructions for resources in real time. Real-time compensation is determined by the dispatch instructions, metered output, and the corresponding LMP.

20. LMP is comprised of three components: The system-wide price of energy, transmission line losses, and the congestion charge. The congestion charge component of LMP is calculated using shift factors when modeled flows are above the intended physical capability of given transmission facilities. A shift factor reflects the positive or negative percentage effect that a one-megawatt change in generation output or demand will have on an identified constraint. These shift factors are used to create a dispatch strategy that is consistent with physical and other reliability constraints. In other words, shift factors allow RTOs/ISOs to manage transmission constraints through congestion charge price signals that relate to a generator's or load's influence on a specific constraint.

21. Prices in the RTO/ISO day-ahead markets and real-time balancing markets can be volatile depending on market conditions. Products designed to hedge RTO/ISO price volatility have provided valuable tools for RTO/ISO market participants to secure predictable revenue streams or reduce price risk associated with generation costs. These price hedging tools have evolved concurrently with changes in wholesale electricity markets.

22. In the RTO/ISO markets, market participants can limit price risk using several tools, notably, virtual offers and bids, FTRs, and internal bilateral contracts. Virtual offers and bids (collectively, virtuals) allow market participants the opportunity, among other things, to transfer price risk between day-ahead and real-time markets within an RTO/ISO. When virtuals are scheduled in the day-ahead market, the financial commitment is established at published day-ahead prices, and virtuals are automatically liquidated with the opposite buy/sell position, in most cases at real-time prices. Virtuals are not backed by physical assets. If a load-serving entity determines that it might need to purchase supply from real-time markets,^[36] the load-serving entity could use virtuals to “lock-in” a day-ahead price.

23. FTRs provide market participants with a mechanism to hedge transmission costs under LMP-based market designs. In general, load-serving entities in RTOs/ISOs are allocated either FTRs or transmission rights convertible into FTRs. This allocation is often based on usage during an historical period. Allocated FTRs are limited to load-serving entities and to those who funded construction of specific transmission facilities. Other FTRs are auctioned, and such FTRs generally can be purchased by creditworthy entities. Moreover, FTRs can be resold outside of the RTO/ISO auction and allocation procedures. Transactions occurring outside of the RTO/ISO allocation and auction procedures are commonly referred to as secondary market transactions.

24. Finally, internal bilateral contracts allow market participants to hedge energy costs under LMP-based market designs. In RTOs/ISOs, market participants can enter into bilateral agreements and use the RTO/ISO to perform settlement functions. These internal bilateral contracts typically rely on a bilaterally negotiated price rather than the potentially more volatile RTO/ISO LMP-based energy price, and they allow market participants the opportunity to transfer risks relating to energy costs among market participants. Thus, a load-serving entity may enter into an internal bilateral contract with a supplier to settle its energy costs at a predetermined rate rather than at the applicable LMP. If the market participant reports this internal bilateral contract to the RTO/ISO, the RTO/ISO would then account for this agreement in its settlement process.

25. RTO/ISO price-hedging products have been created outside of the RTO/ISO markets as well. Electricity futures were first traded on NYMEX in March 1996.^[37] Electricity futures, which are traded on organized exchanges, and electricity forwards, which are traded outside of organized exchanges, are transactions that typically specify a quantity of physical electricity to be delivered at a specific time and place in the future at an agreed-upon price.^[38] A generation owner can sell output from its facility at a pre-determined price by entering into futures or forward transactions even as the RTO/ISO price varies.

26. In recent years, other products for hedging RTO/ISO prices have developed, such as electricity swaps. Swaps are similar to electricity futures and forwards, but swaps are financial transactions that do not require physical delivery. Electricity swaps can be bought or sold at a given “fixed” price and subsequently settle at a “floating” published daily electricity price; this is typically referred to as a “fixed-for-floating” swap. Swaps can act as a hedge when used alongside physical electricity sales, by guaranteeing the generation owner an agreed upon price, notwithstanding fluctuation in the published electricity price. Specifically, if the published daily electricity price is higher than the agreed upon price, the generation owner pays the difference to the counter-party to the swap but still receives the agreed upon price.^[39] This effectively guarantees a predictable revenue stream to the generation owner. RTO/ISO posted prices are one of the commonly referenced settlement values used in electricity swaps.

27. To the extent that any market participant is willing to manipulate the market, that market participant would have an incentive to manipulate RTO/ISO prices that are used to settle values for electricity products, including financial products such as electricity swaps. The likelihood of an attempt at market manipulation can be reduced if the perceived cost of manipulation exceeds the perceived benefit. For example, a market participant may wish to drive up an RTO/ISO price because that market participant also holds an electricity swap that benefits from a higher RTO/ISO price. In that vein, the market participant may offer supply into the RTO/ISO market at levels above its own marginal costs, driving up an RTO/ISO price by requiring a higher-priced unit to be selected. That market participant would receive less revenue from the RTO/ISO due to the lost sales opportunity from its own higher-priced offer not being selected. However, in this example, the market participant may be able to more than offset the reduction in revenue through the benefit of its electricity swap associated with the higher RTO/ISO price.

28. Given the history of electricity markets it regulates, the Commission expects that such markets will continue to evolve, that new physical and financial products will be formed, and that increasingly complex manipulative or other anti-competitive strategies may be created.

A. Market Monitoring and Surveillance

29. To keep pace with market developments, the Commission is proposing to establish ongoing, electronic delivery of data from each RTO and ISO to enhance its market monitoring and surveillance efforts. By seeking electronic delivery of the data outlined in this NOPR, the Commission does not seek to displace or modify any of the existing market monitoring functions performed by MMUs. Nor do we intend our proposal to be perceived as an implicit criticism of the MMUs' performance. Instead, this data will help the Commission detect anti-competitive or manipulative behavior, or ineffective market rules, and thus help ensure just and reasonable rates.

30. Among other objectives, the Commission will use the data it proposes to receive as part of automated screens and other analyses designed to detect attempts to manipulate RTO/ISO pricing for the purpose of benefiting products that settle using RTO/ISO pricing and to detect abuses involving interchange transactions. Supply offer, demand bid, virtual, and FTR data will assist the Commission in understanding how market participants are positioning themselves in RTO/ISO markets. For example, market participants attempting to move RTO/ISO settlement pricing might offer supply into the RTO/ISO market at uncompetitive prices. Likewise, market participants could target specific LMP prices using virtual offers and bids. Because congestion impacts are often spread across many price nodes (and result in many different LMPs) through shift factors, these virtual offers and bids need not be placed at the specific price node for which a market participant might be attempting to move the LMP. Estimated marginal cost and shift factor data will enhance the Commission's ability to identify such behavior that may be designed to impact RTO/ISO pricing. Moreover, interchange pricing data will assist the Commission's efforts to identify anomalous or uneconomic electricity interchange schedules; electricity schedules between markets that are not consistent with pricing signals could be a source of market inefficiency or raise other anti-competitive concerns.

31. Securing data concerning the markets that the RTOs/ISOs administer is part of the Commission's broader effort to enhance its market monitoring and surveillance capabilities. Specifically, in a recently issued NOPR on Commission access to electronic tag (e-Tag) data,^[40] the Commission proposed to make e-Tag data available to the Commission to assist in monitoring the market and preventing manipulation, among other things. In yet another NOPR, the Commission proposed to require additional contract and transaction data from those who file EQRs and to extend the EQR filing requirements to wholesale market participants which fall outside the Commission's FPA section 205 jurisdiction.^[41] The Commission stated that these proposals would strengthen the Commission's ability to identify potential exercises of market power or manipulation. We believe that the same is true here.

32. Utilizing the data the Commission proposes to receive in this NOPR and the two NOPRs addressed above could greatly enhance the Commission's market monitoring and surveillance capabilities. The data will permit the Commission to improve its screening of market participants for illicit behavior, making such conduct more difficult to mask. In addition, the data the Commission proposes to collect in these NOPRs could provide a better picture of legitimate market activity and lessen the possibility that market monitoring and surveillance screens will result in error.

B. Commission Policies and Regulations

33. In overseeing wholesale electricity markets, the Commission evaluates, in response to submissions or on its own motion, existing market designs and the effectiveness of market rules. The Commission proposes to use RTO/ISO market data to more effectively carry out these functions. Electronic delivery of this data will enable the Commission to better identify ineffective market rules and better inform Commission policies and decision-making, and thus help prevent anti-competitive behavior and ensure just and reasonable rates.

34. We believe that electronic delivery of RTO/ISO market data will provide the Commission with empirical information that will augment ongoing industry outreach in determining the effectiveness of the Commission-approved market rules and the efficiency of existing market designs in producing just and reasonable rates. Electronic delivery of the market data sought would allow the Commission to perform better ongoing analysis as markets evolve and new resources begin participating in these markets. For example, the market data sought should enable the Commission to assess both the scheduling practices of renewable resources and how renewable energy schedules compare with actual real-time performance. Because of its unique position, the Commission will be able to perform such analysis across the RTO/ISO markets. This cross-market analysis will enhance the Commission's ongoing efforts to assess the performance of different market designs and rules.

35. In seeking electronic delivery of this data, the Commission emphasizes that it does not seek to displace existing MMU efforts to evaluate market rules and market designs nor is it proposing to modify any of the market monitoring functions performed by MMUs. Rather, the Commission is seeking to augment the assessments currently being performed by MMUs, thus strengthening the Commission's regulatory capabilities through the ongoing electronic delivery of RTO/ISO market data.

C. Requested Data

36. As part of this rulemaking, the Commission proposes to require ongoing electronic delivery of, the data (e.g., the information to be included in the datasets) described below. The Commission invites comment on these data requirements:

1. Supply offers and demand bids for energy and ancillary services—The Commission is proposing that RTOs/ISOs provide their data on supply offers and demand bids submitted to RTO/ISO markets. This dataset would include all offers and bids for energy and ancillary services. This dataset would also include offers and bids submitted for interchange transactions, as well as those submitted without economic consideration, i.e., self schedules.

2. Virtual offers and bids—The Commission is proposing that RTOs/ISOs provide their data on virtual supply offers and virtual demand bids submitted to RTO/ISO markets.

3. Energy/ancillary service awards—The Commission is proposing that RTOs/ISOs provide their data on market awards for energy and ancillary services. This dataset would include the quantity and price of all market awards for energy and ancillary services. The dataset would also identify resources that are self-scheduled.

4. Capacity market offers, designations, and prices—For RTOs/ISOs with centralized capacity markets, the Commission is proposing to require RTOs/ISOs to provide their data on capacity offers as well as capacity market outcomes or designations. This dataset would identify capacity resources, the amount of procured capacity, and the applicable capacity market price.

5. Resource output—The Commission is proposing that RTOs/ISOs provide their data on resource output data used in market settlements. This dataset would include details used in market settlements, including RTO/ISO dispatch instructions (i.e., the output that a dispatched resource is expected to produce in real-time) for energy or ancillary services, or whether resources are operating at self-scheduled output levels, and measured output levels.

6. Marginal cost estimates—The Commission is proposing that RTOs/ISOs provide their data on marginal cost estimates; such estimates are typically generated for the potential replacement of supply offers in market power mitigation procedures. This dataset would include all marginal cost estimates that have been developed, and not just those estimates that were used to generate mitigated supply offers. The Commission is seeking just the resulting marginal cost estimates themselves, however, and is not proposing that RTOs/ISOs provide the inputs that allow for calculation of those estimates. Further, the Commission is not seeking other operating information regarding individual generators' actual costs, revenues, or profits.

7. Day-ahead shift factors—The Commission is proposing that RTOs/ISOs provide their data on shift factors calculated for use in the day-ahead market. This would include generation shift factors, which are factors to be applied to a generator's expected change in output to determine the amount of flow contribution that that change in output will impose on an identified transmission facility or flowgate, and load shift factors, which are factors to be applied to a load's expected change in demand to determine the amount of flow contribution that that change in demand will impose on an identified transmission facility or flowgate. This dataset would not be limited to binding constraints, but should also include all shift factors calculated to address non-binding constraints.

8. FTR data—The Commission is proposing that RTOs/ISOs provide their data on FTR transactions that may not be publicly posted in all RTO/ISO markets. Specifically, the Commission is proposing that RTOs/ISOs provide data detailing how all FTRs and allocated rights were acquired, either through RTO/ISO allocation or auction procedures; data detailing whether the acquired allocation positions were converted from positions that collect auction revenue into positions that collect congestion revenue; and data detailing secondary market transactions to the extent that they are available to the RTO/ISO.

9. Internal Bilateral Contracts—The Commission is proposing that RTOs/ISOs provide their data on the settlement of internal bilateral contracts for energy.

10. Pricing data for interchange transactions—The Commission is proposing that RTOs/ISOs provide their data on pricing information for scheduled interchanges. Scheduled interchanges include any transaction between two or more Balancing Authority Areas. To enhance the Commission's market monitoring and surveillance efforts, the Commission is proposing that eTag IDs be included, when applicable, in addition to other interchange pricing details and transaction identification.

37. The data that the Commission is proposing to receive electronically in this NOPR are limited to physical and virtual offers and bids, market awards, resource outputs, marginal cost estimates, shift factors, FTRs, internal bilateral contracts, and interchange pricing. These datasets would include descriptive information such as market participant names, unique identifiers, pricing points, and other information that the Commission considers necessary and appropriate to understand and analyze the data described in this NOPR. Markets are not static, however, and, as markets continue to evolve, the Commission may initiate a new rulemaking process in the future to reassess the data necessary for its market monitoring and surveillance efforts and for its policy and decision-making needs.

38. The Commission proposes that RTOs/ISOs be required to electronically deliver the data discussed in this NOPR to the Commission within seven days after each RTO/ISO creates the datasets in a market run or otherwise. For example, day-ahead offers and bids, market awards, resource outputs, day-ahead shift factors, internal bilateral contracts, and day-ahead interchange pricing data would be required to be electronically delivered within seven days after the completion of each day-ahead market run. Real-time offers and bids and real-time interchange pricing data would be required to be electronically delivered within seven days after the completion of each real-time market run. For data that are updated less frequently, including capacity market results, estimated marginal costs, and FTR data, each RTO/ISO would be expected to electronically deliver that data within seven days after it is created or updated by the RTO/ISO. For the initial delivery of data under this proposal, however, the Commission proposes that each RTO/ISO would be required to electronically deliver all such data forty-five days after the effective date of any final rule in this proceeding. Finally, if the RTO/ISO makes later corrections to the data (after they have been delivered to the Commission), the RTO/ISO would be expected to electronically deliver the corrected data to the Commission within seven days after the correction has been made. The Commission invites comments with respect to the timeframe in which the data described in this NOPR should be electronically delivered to the Commission.

39. The Commission proposes to locate the requirement to electronically deliver this data on an ongoing basis within section 35.28(g) of our regulations. Further, the Commission proposes to direct each RTO/ISO to submit a compliance filing amending its open access transmission tariff to reflect this requirement within forty-five days after the effective date of any final rule in this proceeding.

D. Data Formatting and Web-Based Delivery

40. In order to facilitate the Commission's efforts described above, the Commission is proposing to require each RTO and ISO to use consistent formatting and delivery methods to electronically deliver the data described in this NOPR to the Commission. Consistent formatting and delivery methods will enable the Commission to develop routine data procedures to link RTO/ISO and other market data, thus enabling automated analytic techniques.

41. In regard to data formatting, the Commission is proposing to require that any data outlined in this NOPR be in an XML format that is consistent for all RTOs/ISOs when electronically delivered to the Commission. As stated above, the Commission is not proposing that each RTO/ISO materially modify the data prior to electronic delivery to the Commission.^[42]

42. In Order No. 714,^[43] the Commission adopted XML format for entities to use when making tariff related filings, based upon industry agreement.^[44] XML is also commonly used by RTOs/ISOs to deliver data to market participants through Open Access Same-Time Information Systems (OASIS) and other purposes. Data not formatted in XML may also be extracted directly from a database into an XML-formatted file using automated procedures. However, the Commission also recognizes that XML, which was adopted by the industry as the most effective format to use when electronically filing tariffs, may not be the preferred format to use when electronically delivering RTO/ISO data. Accordingly, we seek comment on this issue.

43. In regard to the data delivery method, the Commission is proposing that each RTO and ISO use a secure data delivery method to provide data to the Commission due to the commercially-sensitive nature of the market data described in this NOPR. Specifically, the Commission is proposing that any RTO/ISO market data be electronically delivered using the Secure File Transfer Protocol (SFTP). Delivery by SFTP is similar to delivery by File Transfer Protocol or “FTP,” a widely-used file-sharing protocol; except that all communications transmitted using SFTP are encrypted. Access to the server where the data is electronically delivered will only be granted to each applicable RTO and ISO and to the Commission.

44. Accordingly, and as part of our consideration of the range of possible formats and delivery methods that RTOs/ISOs may use to electronically deliver data to the Commission, the Commission invites comments with respect to efficient and secure ways to provide the Commission with RTO/ISO data. The Commission also invites comment on the time and resources that may be needed by RTOs/ISOs for the initial implementation and ongoing compliance with the proposed requirements of this rule. Finally, the Commission invites comment on whether a phased implementation approach should be undertaken, and, if so, what a potential phased approach should entail.

E. Non-Public Data

45. Much of the information that the Commission expects to receive in this proposal is, by its nature, commercially-sensitive.^[45] Disclosure of such information could result in competitive harm to market participants and the market as a whole.^[46] Accordingly, the Commission proposes that the data sought in this proceeding is to be kept non-public and not be made publicly available,^[47] except as may be directed by the Commission, or a court with appropriate jurisdiction.^[48]

46. To the extent the data collected pursuant to this rulemaking are used, for example, to support proposed market rule changes, the analysis relied upon by the Commission will be publicly available except that confidential market information and other protected or confidential information will remain non-public. Also, the Commission may direct its staff to publicly issue a staff report outside of a rulemaking proceeding with similar protections for confidential or otherwise protected information.

III. Information Collection Statement

47. The collections of information contained in this proposed rule have been submitted to the Office of Management and Budget (OMB) for review under section 3507(d) of the Paperwork Reduction Act of 1995, 44 U.S.C. 3507(d). The Commission solicits comments on the Commission's need for this information, whether the information will have practical utility, the accuracy of the provided burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques. Respondents subject to the filing requirements of this rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB Control number.

48. The proposed rule does not require market participants other than the RTOs/ISOs to report information to the Commission.

49. The Commission's estimated reporting burden related to the proposed rule in Docket RM11-17-000 follow.

Data collection, proposed FERC-921	Number of respondents	Implementing burden		Annual recurring operating burden		Average annual burden (implementation cost averaged over 3 yrs.)
		Burden hrs. per respondent	Cost per respondent	Burden hrs. per respondent	Cost per respondent	Burden hrs. for all respondents	Cost for all respondents
Compliance filing	6	7	$1,750			14	$3,500
Web-Based Delivery	6	1,040	100,864	40	$3,879	2,320	225,003
Grand Total, Average Annual Estimates	6					2,334	228,503

50. The Commission recognizes that there will be an initial implementation burden associated with providing the Commission with RTO/ISO data. This includes submitting a compliance filing to the Commission, which the Commission estimates as a burden of 7 hours per RTO/ISO, and implementing a process to automatically upload data to an SFTP site for Commission use (including development, testing and production). The Commission estimates a burden of 1040 hours per RTO/ISO for the development, testing and production of an automated process to provide the Commission with the data described in this NOPR. In this regard, though, RTO/ISO markets have already developed capabilities necessary to handle RTO/ISO data in an automated manner. For instance, through their Open Access Same-time Information Systems (OASIS), RTOs/ISOs already make certain market data publically available in XML format using automated procedures. Likewise, some RTOs/ISOs have developed procedures similar to those proposed in this NOPR to deliver data to their MMUs.

51. For the recurring effort involved in electronically delivering RTO/ISO data to the Commission, the Commission anticipates that the additional burden associated with this rule will be minimal. Any recurring burden would be associated with addressing updates to RTO/ISO data as the data that they process changes and due to occasional errors in the data handling or data upload process.

Information Collection Costs: The Commission has estimated the cost of compliance per RTO/ISO to be $102,614 in the initial year of implementation and $3,879 in subsequent years. The Commission expects that the compliance filing will be completed by RTO/ISO legal staff and has estimated an hourly rate at $250/hour. The Commission estimates that a variety of staff, including legal, database administrators and IT and information security specialists, will be required to electronically deliver to the Commission the RTO/ISO data described in this NOPR. The Commission estimated the average hourly cost for this task to be $96.98/hour (including legal staff at $250/hour, information systems manager at $105.35/hour, database administrator at $55.61/hour, and information security analyst at $57.67/hour).^[49]

Title: Proposed FERC-921.^[50] .

Action: Proposed collection.

OMB Control No.: To be determined.

Respondents for this Rulemaking: RTOs and ISOs.

Frequency of Information: Initial implementation, compliance filing, and automated daily updates.

52. Necessity of Information: As wholesale electricity markets continue to develop and evolve, new opportunities arise for anti-competitive or manipulative behavior. The Commission's market monitoring and surveillance capabilities and associated data requirements must keep pace with market developments and evolve along with the markets. The data discussed in this NOPR will allow the Commission to more effectively identify and address such behavior; to identify ineffective market rules; to better inform Commission policies and regulations; and thus to help ensure just and reasonable rates.

53. Internal Review: The Commission has made a preliminary determination that the proposed revisions are necessary to keep pace with ever-changing possibilities for anti-competitive or manipulative behavior and to better inform Commission policies and regulations, and thus to ensure that rates are just and reasonable. The Commission has assured itself, by means of its internal review, that there is specific, objective support for the burden estimate associated with the information requirements.

54. Interested persons may obtain information on the reporting requirements by contacting the Federal Energy Regulatory Commission, Office of the Executive Director, 888 First Street, NE., Washington, DC 20426 [Attention: Ellen Brown, e-mail: [e-mail], phone: [phone], fax: [phone]].

55. Comments concerning the information collections proposed in this NOPR and the associated burden estimates, should be sent to the Commission in this docket and may also be sent to the Office of Management and Budget, Office of Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security reasons, comments should be sent by e-mail to OMB at the following e-mail address: [e-mail]. Please reference FERC-921 and the docket number of this proposed rulemaking (Docket No. RM11-17-000) in your submission.

IV. Environmental Analysis

56. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.^[51] The Commission has categorically excluded certain actions from these requirements as not having a significant effect on the human environment.^[52] The actions proposed here fall within a categorical exclusion in the Commission's regulations, i.e., they involve information gathering, analysis, and dissemination.^[53] Therefore, environmental analysis is unnecessary and has not been performed.

V. Regulatory Flexibility Act Certification

57. The Regulatory Flexibility Act of 1980 (RFA) ^[54] generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. The RFA mandates consideration of regulatory alternatives that accomplish the stated objectives of a rule and that minimize any significant economic impact on a substantial number of small entities. The Small Business Administration's (SBA) Office of Size Standards is responsible for the definition of a small business.^[55] The SBA has established a size standard for utilities, stating that a firm is small if, including its affiliates, it is primarily engaged in the transmission, generation and/or distribution of electric energy for sale and its total electric output for the preceding twelve months did not exceed four million megawatt hours.^[56] RTOs and ISOs are not small entities, and they are the only entities impacted directly by this proposed rule.

58. CAISO is a nonprofit organization with over 54,000 megawatts of capacity and over 25,000 circuit miles of transmission lines.

59. NYISO is a nonprofit organization that oversees wholesale electricity markets serving 19.2 million customers. NYISO manages a nearly 11,000-mile network of high-voltage transmission lines.

60. PJM is comprised of more than 700 members including power generators, transmission owners, electricity distributers, power marketers, and large industrial customers and serves 13 states and the District of Columbia.

61. SPP is comprised of 63 members serving 6.2 million households in nine states and has 48,930 miles of transmission lines.

62. Midwest ISO is a nonprofit organization with over 145,000 megawatts of installed generation. Midwest ISO has over 57,600 miles of transmission lines and serves 13 states and one Canadian province.

63. ISO-NE is a regional transmission organization serving six states in New England. The system is comprised of more than 8,000 miles of high-voltage transmission lines and over 300 generators.

64. The Commission believes this proposed rule will not have a significant economic impact on a substantial number of small entities, and therefore no regulatory flexibility analysis is required.

VI. Comment Procedures

65. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due December 27, 2011. Comments must refer to Docket No. RM11-17-000, and must include the commenter's name, the organization they represent, if applicable, and their address.

66. The Commission encourages comments to be filed electronically via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing.

67. Commenters that are not able to file comments electronically must send an original copy of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street, NE., Washington, DC 20426.

68. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

VII. Document Availability

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

70. From the Commission's Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary both 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.

71. User assistance is available for eLibrary and the Commission's Web site during normal business hours from the Commission's Online Support at 202-502-6652 (toll free at 1-866-208-3676) or e-mail at [e-mail], or the Public Reference Room at 202-502-8371, TTY 202-502-8659. E-mail the Public Reference Room at [e-mail].

List of Subjects in 18 CFR Part 35

• Electric power rates
• Electric utilities
• Reporting and recordkeeping requirements

By direction of the Commission. Commissioner Spitzer is not participating.

Nathaniel J. Davis, Sr.,

Deputy Secretary.

In consideration of the foregoing, the Commission proposes to revise Chapter I, Title 18 of the Code of Federal Regulations to read as follows:

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

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

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

2. In § 35.28, paragraphs (g)(4) through (g)(6) are redesignated as paragraphs (g)(5) through (g)(7) and a new paragraph (g)(4) is added to read as follows:

§ 35.28.

Non-discriminatory open access transmission tariff.

* * * * *

(g) Tariffs and operations of Commission-approved independent system operators and regional transmission organizations.

* * * * *

(4) Electronic delivery of data. Each Commission-approved regional transmission organization and independent system operator must electronically deliver to the Commission, on an ongoing basis and in a form and manner acceptable to the Commission, data related to the markets that the regional transmission organization or independent system operator administers.

* * * * *

Footnotes

1.  16 U.S.C. 825(b), 825f(a).

2.  Counted among such forces are the Northeast blackout of 1965 and the responses to perceived transmission system insufficiencies, as well as the subsequent oil crisis of 1973. For a discussion of developments following the 1965 blackout, see William F. Fox, Jr., Federal Regulation of Energy 749, 755 (1983 & Supp. 1993), and Stephen Breyer and Paul W. MacAvoy, The Federal Power Commission and the Coordination Problem in the Electrical Power Industry, 46 S. Cal. L. Rev. 661, 661 (1973).

3.  Public Utility Regulatory Policies Act of 1978, Pub. L. No. 95-617, 92 Stat. 3117 (1978) (codified as amended in scattered sections of 16 U.S.C.); see, e.g., 16 U.S.C. 824a-3, 824i, 824j.

4.  See, e.g., Louisville Gas & Elec. Co., 62 FERC ¶ 61,016, at 61,143 & n.16, 61,149 (1993) (accepting non-traditional, market-based rates as consistent with primary regulatory goal of ensuring lowest reasonable cost energy to consumers, provided service is reliable and the seller demonstrates a lack of market power); Pac. Gas & Elec. Co., 38 FERC ¶ 61,242, at 61,790 (1987) (accepting proposed competitive rates because “competition * * * encourages utilities to make efficient decisions with a minimum of regulatory intervention [and, u]ltimately, consumers should benefit from lower prices as competition improves efficiency.”), modifying on other ground, 47 FERC ¶ 61,121 (1989), modified, 50 FERC ¶ 61,339 (1990), modified sub nom. W. Sys. Power Pool, 55 FERC ¶ 61,099, at 61,319 (addressing applicant's failure to eliminate anticompetitive effects by mitigating market power), granting stay, 55 FERC ¶ 61,154, reh'g granted in part, 55 FERC ¶ 61,495 (1991), modified, 59 FERC ¶ 61,249 (1992); Pub. Serv. Co. of New Mexico, 25 FERC ¶ 61,469, at 62,038 (1983) (averring that “competition penalizes a seller that is inefficient or has an unreasonable pricing strategy[; consequently,] consumers * * * benefit because the improvements in efficiency lead to lower prices.”); see also Heartland Energy Servs., Inc., 68 FERC ¶ 61,223 (1994) (reviewing early Commission decisions granting market-based rate authority).

5.  Pub. L. No. 102-486, 106 Stat. 2776 (1992).

6.  Fla. Mun. Power Agency v. Fla. Power & Light Co., 65 FERC ¶ 61,125, at 61,615, reh'g dismissed, 65 FERC ¶ 61,372 (1993), final order, 67 FERC ¶ 61,167 (1994), order on reh'g, 74 FERC ¶ 61,006 (1996).

7.  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).

8.  Open Access Same-Time Information System and Standards of Conduct, Order No. 889, FERC Stats. & Regs. ¶ 31,035 (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).

9.  Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,634.

10.  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), order on reh'g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

11.  Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,652; see also id. at 31,730-32.

12.  Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6, 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).

13.  See ISO/RTO Council, Progress of Organized Wholesale Electriciy Markets in North America 1 (2007), http://www.isorto.org/​atf/​cf/​%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/​IRC_​State_​of_​the_​Markets_​Report_​103007.pdf.

14.  See Federal Energy Regulatory Commission, 2008 State of the Markets Report (2009), available at http://www.ferc.gov/​market-oversight/​st-mkt-ovr/​2008-som-final.pdf. We also note that financial electricity products may be transacted (1) Through exchanges besides ICE (e.g., NYMEX and Nodal Exchange), (2) by voice brokers, (3) bilaterally, or (4) by using other means.

15.  Revised Public Utility Filing Requirements, Order No. 2001, FERC Stats. & Regs. ¶ 31,127, reh'g denied, Order No. 2001-A, 100 FERC ¶ 61,074, reh'g denied, Order No. 2001-B, 100 FERC ¶ 61,342, order directing filing, Order No. 2001-C, 101 FERC ¶ 61,314 (2002), order directing filing, Order No. 2001-D, 102 FERC ¶ 61,334, order refining filing requirements, Order No. 2001-E, 105 FERC ¶ 61,352 (2003), order on clarification, Order No. 2001-F, 106 FERC ¶ 61,060 (2004), order revising filing requirements, Order No. 2001-G, 120 FERC ¶ 61,270, order on reh'g and clarification, Order No. 2001-H, 121 FERC ¶ 61,289 (2007), order revising filing requirements, Order No. 2001-I, FERC Stats. & Regs. ¶ 31,282 (2008).

16.  Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, clarified, 121 FERC ¶ 61,260 (2007), order on reh'g, Order No. 697-A, FERC Stats. & Regs. ¶ 31,268, clarified, 124 FERC ¶ 61,055, order on reh'g, Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 (2008), order on reh'g, Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 (2009), order on reh'g, Order No. 697-D, FERC Stats. & Regs. ¶ 31,305 (2010), aff'd sub nom. Montana Consumer Counsel v. FERC, No. 08-71827, 2011 U.S. App. LEXIS 20724 (9th Cir. Oct. 13, 2011). In its decision upholding Order No. 697, the Ninth Circuit Court of Appeals noted that monitoring must be accompanied by enforcement because “[w]ithout enforcement, there is little reason to believe that sellers will police themselves.” Montana Consumer Counsel, 2011 U.S. App. LEXIS 20724 at *19 n.5.

17.  Charles H. Koch, Jr., Collaborative Governance: Lessons for Europe from U.S. Electricity Restructuring, 61 Admin. L. Rev. 71, 97 (2009).

18.  Public Law No. 109-58, 119 Stat. 594 (2005).

19.  See, e.g., 16 U.S.C. 824v.

20.  See 16 U.S.C. 825o (criminal penalties); 16 U.S.C. 825o-1 (civil fines).

21.  Prior to this first generic consideration of MMUs in Order No. 2000, the Commission addressed market monitoring in connection with individual RTO/ISO proposals . See Pac. Gas & Elec. Co., 77 FERC ¶ 61,265 (1996), order on reh'g, 81 FERC ¶ 61,122 (1997), order on clarification, 83 FERC ¶ 61,033 (1998) (requiring the ISO to file a detailed monitoring plan and listing minimum elements for such a plan); Pennsylvania-New Jersey-Maryland Interconnection, 81 FERC ¶ 61,257 (1997) (requiring PJM Interconnection, L.L.C. to develop a market monitoring program to evaluate market power and market design flaws).

22.  Market Monitoring Units in Regional Transmission Organizations and Independent System Operators, 111 FERC ¶ 61,267 (2005) (2005 Policy Statement); Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281 (2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).

23.  2005 Policy Statement, 111 FERC ¶ 61,267 at P 2.

24.  Specifically, MMU functions consist of evaluating existing and proposed market rules, tariff provisions, and market design elements and recommending changes, if applicable; reviewing and reporting on the performance of wholesale markets; and identifying and notifying the Commission of behavior that may require investigation. See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 354.

25.  See, e.g., Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 314.

26.  Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,156-57.

27.  Id.

28.  See 16 U.S.C. 824d, 824e.

29.  See 16 U.S.C. 824v.

30.  16 U.S.C. 825(b).

31.  16 U.S.C. 825f(a).

32.  The Commission is currently considering providing an XML Schema Definition (XSD) that describes the structure of the XML document to be electronically delivered to the Commission. XSD defines those elements, attributes, data types, and any default or fixed values in the XML. Depending on how the requested data is stored by each RTO/ISO, some data transformation may be required to prepare XML that is consistent with the XSD. For example, one RTO/ISO might store dates in MM-DD-YYYY format while the rest use YYYY-MM-DD format. As such, an XSD might specify that dates in the XML be electronically delivered to the Commission in YYYY-MM-DD format.

33.  The estimated marginal cost data the Commission proposes to receive through this NOPR do not include individual generators' actual costs, revenues, or profits.

34.  We note that currently CAISO and SPP do not administer a centralized capacity market.

35.  We note that other inputs, including generation capabilities and other system costs, inter alia, are used by RTOs/ISOs to arrive at the lowest-cost solution.

36.  A load-serving entity might determine such a need to purchase supply, for example, because of potential weather-related events or generator malfunction.

37.  S.J. Deng and S.S. Oren, Electricity derivatives and risk management, 31 Energy 940, 943 (2006), available at http://www.sciencedirect.com.

38.  See id. at 942-43.

39.  For example, Generator sells to the RTO/ISO at a market-based rate, which varies according to the market. As a hedge, Generator sells a financial swap to Counter-party at $30/MWh. If the published electricity price that Generator receives on day one is $20/MWh, Counter-party pays Generator the difference, i.e., $10 ($30 minus $20). Thus, Generator receives the agreed upon price of $30/MWh. Conversely, if the published electricity price that Generator receives on day two is $45/MWh, Generator owes Counter-party the difference, i.e., $15 ($45 minus $30). Thus, Generator again receives the agreed upon price of $30/MWh.

40.  Availability of E-Tag Information to Commission Staff, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,675 (2011).

41.  Electricity Market Transparency Provisions of Section 220 of The Federal Power Act, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,676 (2011).

42.  See supra P 14.

43.  Electronic Tariff Filings, Order No. 714, 73 FR 57515, FERC Stats. & Regs. ¶ 31,276 (2008).

44.  Order No. 714, FERC Stats. & Regs. ¶ 31,276 at P 30.

45.  In the past, the Commission has granted requests for privileged or confidential treatment of similar non-public data. See, e.g., N.Y. Indep. Sys. Operator, Inc., 131 FERC ¶ 61,169, at P 15 (2010) (granting such treatment for data relating to specific generator or other equipment details, transmission system information, bidding strategies, generator reference levels, generator costs, guarantee payments, and the associated relevant time periods); see also So. Cal. Edison Co., 135 FERC ¶ 61,201, at P 20; Hydrogen Energy Cal. LLC, 135 FERC ¶ 61,068, at P 25 (2011); N.Y. Indep. Sys. Operator, Inc., 130 FERC ¶ 61,029, at P 3 (2010).

46.  Section 301(b) of the FPA, 16 U.S.C. 825(b), provides that no member, officer, or employee of the Commission may divulge any fact or information that may come to his knowledge during the course of examination of books or other accounts, except as may be directed by the Commission or by a court.

47.  We note that, notwithstanding that the Commission may have data available to it, complainants still must bear the burden of making a prima facie case; complainants must do more than make unsubstantiated allegations. Interstate Power & Light Co. v. ITC Midwest, LLC, 135 FERC ¶ 61,162, at P 18 (2011); see also UNITIL Power Corp. v. Pub. Serv. Co. of N.H., 62 FERC P 61,055, at 61,287 (1993) (“The question we must answer at this stage of the proceeding is whether UNITIL has presented sufficient evidence of PSNH's costs so that we may assess whether a trial-type, evidentiary hearing is warranted.”); Houlton Water Co. v. Me. Pub. Serv. Co., 55 FERC P 61,037, at 61,110 (1991) (“Maine Public correctly states that a customer seeking a section 206 investigation of existing rates must provide some basis to question the reasonableness of the overall rate level, taking into account changes in all cost components and not just [the item being challenged].”).

48.  We note that the Freedom of Information Act (FOIA) allows persons to file requests to obtain data from the Commission. However, commercially-sensitive data, like that described in this NOPR, is covered by exemption 4 of FOIA, which protects “trade secrets and commercial or financial information obtained from a person [that is] privileged or confidential.” 5 U.S.C. 552(b)(4) (2006), amended by OPEN Government Act of 2007, Pub. L. No. 110-175, 121 Stat. 2524 (2007); accord 18 CFR 388.107(d).

49.  Hourly average wage is an average and was calculated using Bureau of Labor Statistics (BLS), Occupational Employment Statistics data for May 2010 (at http://www.bls.gov/​oes/​) for the database administrator and information security analysts. The average hourly figure for legal staff and information systems manager is a composite from BLS and other resources. The following weightings were applied to estimate the average hourly cost: Legal staff (1/6), information systems manager (1/6), database administrator (1/3), and information security analyst (1/3).

50.  OATT compliance filings (like the one-time compliance filing here) are normally included under FERC-516 (OMB Control No. 1902-0096). However, the reporting requirements (including the compliance filing) contained in this proposed rule in Docket No. RM11-17 will be covered by a proposed FERC-921.

51.  Regulations Implementing the National Environmental Policy Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987).

52.  18 CFR 380.4.

53.  See 18 CFR 380.4(a)(5).

54.  5 U.S.C. 601-612.

55.  13 CFR 121.101.

56.  13 CFR 121.201 (Sector 22, Utilities).