# 72 FR 36276: Wholesale Competition in Regions With Organized Electric Markets

> Federal · Regulations · In force

URL: https://www.frixlaw.com/law-library/statutes/FR_PRORULE_E7-12550

## Section

- **Citation:** 72 FR 36276
- **Heading:** Wholesale Competition in Regions With Organized Electric Markets
- **Jurisdiction:** Federal
- **Kind:** Regulations
- **Status:** In force
- **Text as of:** August 14, 2026
- **Source:** Compiled text
- **Location:** Federal Register / Vol. 72 / 72 FR 36276

## Text

DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket Nos. RM07-19-000 and AD07-7-000] Wholesale Competition in Regions With Organized Electric Markets June 22, 2007. AGENCY:
Federal Energy Regulatory Commission, DOE.

ACTION:
Advance notice of proposed rulemaking.

SUMMARY:
The Federal Energy Regulatory Commission (Commission) is issuing an Advance Notice of Proposed Rulemaking (ANOPR) with regard to potential reforms to improve the operation of organized wholesale electric markets. The Commission invites all interested persons to submit comments in response to specific questions.

DATES:
Comments on this ANOPR are due on August 16, 2007.

ADDRESSES:
You may submit comments identified by Docket Nos. RM07-19-000 and AD07-7-000 by one of the following methods:
• Agency Web Site: http://www.ferc.gov . Follow the instructions for submitting comments via the eFiling link found in the Comment Procedures section of the ANOPR.
• Mail: Commenters unable to file comments electronically must mail or hand deliver an original and 14 copies of their comments to the Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street, NE., Washington, DC 20426. Please refer to the Comment Procedures section of the ANOPR for additional information on how to file paper comments.
FOR FURTHER INF0RMATION CONTACT:
David Kathan (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, David.Kathan@ferc.gov , (202) 502-6404. Elizabeth Rylander (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Elizabeth.Rylander@ferc.gov , (202) 502-8466.

SUPPLEMENTARY INFORMATION:
Paragraph numbers I. Introduction 1 II. Background 4 A. Brief History 14 B. Competition Issues and Commission Actions 25 C. Issues Addressed in the ANOPR 30 III
-6404. Elizabeth Rylander (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Elizabeth.Rylander@ferc.gov , (202) 502-8466.

SUPPLEMENTARY INFORMATION:
Paragraph numbers I. Introduction 1 II. Background 4 A. Brief History 14 B. Competition Issues and Commission Actions 25 C. Issues Addressed in the ANOPR 30 III. Demand Response and Pricing During Power Shortages in Organized Markets 34 A. Importance of Demand Response to Competition in RTO/ISO Areas 36 B. Prior Commission Actions To Address Demand Response 41 C. Remaining Problems with Demand Response in Organized Markets 47 D. Proposed Commission Actions To Improve Demand Response and Market Pricing During a Power Shortage 57 IV. Long-Term Power Contracting in Organized Markets 83 A. Importance of Long-Term Power Contracts and Factors Affecting Contracting Decisions by Buyers and Sellers 84 B. Commission Actions To Support Long-Term Power Contracts 88 C. Proposed Commission Actions To Facilitate Long-Term Power Contracting 92 V. Market Monitoring Policies 95 A. History of Market Monitoring 98 B. Independence and Function 108 C. Information Sharing 122 D. Pro Forma Tariff Section 131 E. Conclusion 132 VI. Responsiveness of RTOS and ISOS 133 A. The Challenge of Improving RTO and ISO Responsiveness to Stakeholders 134 B. Prior Commission Actions Regarding RTO and ISO Responsiveness 140 C. Proposed Commission Action To Improve RTO and ISO Responsiveness 146 VII. Additional Questions 164 VIII. Comment Procedures 166 IX. Document Availability 170 I. Introduction
1. The Federal Energy Regulatory Commission (Commission) is considering potential reforms to improve the operation of organized wholesale electric markets. 1 In response to issues raised by various market participants and industry observers about improvements to enhance wholesale electric markets, the Commission held two conferences, on February 27, 2007 and May 8, 2007, to learn more about these issues
Federal Energy Regulatory Commission (Commission) is considering potential reforms to improve the operation of organized wholesale electric markets. 1 In response to issues raised by various market participants and industry observers about improvements to enhance wholesale electric markets, the Commission held two conferences, on February 27, 2007 and May 8, 2007, to learn more about these issues. The first dealt with all wholesale power markets while the second focused on organized RTO/ISO markets. Based on the comments received at these two conferences, the Commission identified four specific and narrow issues, as described below, that are not already being fully addressed by the Commission in other proceedings and that may be appropriate to address in a generic proceeding.
1 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.
2. These issues are: (1) The role of demand response in organized markets, including greater reliance on market prices to elicit demand reductions during power shortages; (2) increasing opportunities for long-term power contracting; (3) strengthening market monitoring; and (4) the responsiveness of RTOs and ISOs to customers and other stakeholders. This Advance Notice of Proposed Rulemaking (ANOPR) identifies specific concerns in these four areas and presents the Commission's preliminary views on proposed reforms. 2 The Commission seeks
2 Throughout this document, the term “propose” is used as a short form of stating that it is the Commission's preliminary view that the proposal that follows may be a reasonable way to achieve a regulatory objective, and that the Commission requests comments on the proposal and on
3
in these four areas and presents the Commission's preliminary views on proposed reforms. 2 The Commission seeks
2 Throughout this document, the term “propose” is used as a short form of stating that it is the Commission's preliminary view that the proposal that follows may be a reasonable way to achieve a regulatory objective, and that the Commission requests comments on the proposal and on
3. Finally, the actions proposed here are intended to complement other Commission actions, discussed further below, intended to improve the operation of wholesale competition in regions with and without RTOs and ISOs and their organized markets. There are opportunities to improve the operation of wholesale markets in both types of regions. Many of the Commission's prior actions—such as Order No. 890 3 —apply to both types of regions, while others by their nature apply only to RTO/ISO regions, such as assuring load-serving entities (LSEs) of long-term transmission rights in regions with locational marginal pricing and congestion hedges. The issues being explored in this proceeding are discrete and apply to regions with organized spot markets, market monitors, and an RTO or ISO. The actions considered address concerns that numerous market participants and many of our state colleagues have raised in this proceeding and elsewhere. The Commission is not seeking to fundamentally redesign organized markets or to appropriate jurisdiction from our state colleagues. Our goal is to make incremental improvements to the operation of organized markets without undoing or upsetting the significant efforts that have already been made in providing demonstrable benefits to wholesale customers. In particular, we acknowledge and commend the ISOs and RTOs and their respective transmission owners and stakeholders for their work over the past several years in fulfilling the Commission's policies supporting wholesale competition and non-discriminatory access to transmission
upsetting the significant efforts that have already been made in providing demonstrable benefits to wholesale customers. In particular, we acknowledge and commend the ISOs and RTOs and their respective transmission owners and stakeholders for their work over the past several years in fulfilling the Commission's policies supporting wholesale competition and non-discriminatory access to transmission.
3 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12,266 (Feb. 16, 2007), FERC Stats. & Regs. ¶ 31,241 (2007), reh'g pending (Reform of the Open Access Transmission Tariff (OATT) rules or OATT Reform).
II. Background
4. National policy for many years has been, and continues to be, to foster competition in wholesale power markets. As the third major federal law enacted in the last 30 years to embrace wholesale competition, the Energy Policy Act of 2005 (EPAct 2005) 4 strengthened the legal framework for continuing wholesale competition as federal policy for this country.
4 Pub. L. No. 109-58, 119 Stat. 594 (2005).
5. The Commission's core responsibility is to “guard the consumer from exploitation by non-competitive electric power companies.” 5 The Commission has always used two general approaches to meet this responsibility—regulation and competition. The first was the primary approach for most of the last century and remains the primary approach for wholesale transmission service, and the second has been the primary approach in recent years for wholesale generation service.
5 National Association for the Advancement of Colored People v. FPC , 520 F.2d 432, 438 (D.C. Cir. 1975), aff'd , 425 U.S. 662 (1976).
6. The Commission has never relied exclusively on competition to assure just and reasonable rates and has never withdrawn from regulation of wholesale electric markets. Rather, the Commission has shifted the balance of the two approaches over time as circumstances changed
l Association for the Advancement of Colored People v. FPC , 520 F.2d 432, 438 (D.C. Cir. 1975), aff'd , 425 U.S. 662 (1976).
6. The Commission has never relied exclusively on competition to assure just and reasonable rates and has never withdrawn from regulation of wholesale electric markets. Rather, the Commission has shifted the balance of the two approaches over time as circumstances changed. Advances in technology, exhaustion of economies of scale in most electric generation, and new federal and state laws have changed our views of the right mix of these two approaches. Our goal has always been to find the best possible mix of regulation and competition to protect consumers from the exercise of monopoly power.
7. In each major energy bill over the last few decades, Congress has acted to open up the wholesale electric power market by facilitating entry of new generators to compete with traditional utilities. The Commission has acted quickly and strongly over the years to implement this national policy.
8. Congress has not deregulated the wholesale electric power business, however, and the Commission has not done so by regulation. To the contrary, the Commission has issued many new regulations and orders designed to foster competition nationally and to support competitive markets in specific regions. Because the United States does not have a national electric power market, our approach to implementing competition has been to recognize and foster the development of regional markets.
9. There are significant differences among the regional wholesale power markets. There are differences in industry structure, differences in the mix of ownership (such as investor-owned, cooperatively-owned, and publicly-owned utilities), differences in the mix of fuels and energy sources for electric generation, and differences in population densities and weather patterns, to name a few
arkets.
9. There are significant differences among the regional wholesale power markets. There are differences in industry structure, differences in the mix of ownership (such as investor-owned, cooperatively-owned, and publicly-owned utilities), differences in the mix of fuels and energy sources for electric generation, and differences in population densities and weather patterns, to name a few. Some regions pursue wholesale competition exclusively by relying on direct bilateral contracting between sellers and buyers, and others employ a mix of bilateral contracting with organized spot markets and other markets to increase opportunities for the sale or purchase of electric power. In regions with organized spot markets, the markets are administered by an RTO or ISO, which themselves have differences regarding such matters as market design, transmission responsibilities, and decision-making procedures. The Commission's approach to supporting wholesale competition is to recognize and respect these differences in market structure and other differences across the various regions.
10. Wholesale competition can serve customers well in all regions, including RTO and ISO regions with organized markets and regions without such organizations and markets. There are strengths and weaknesses to the approach taken by each, and wholesale competition faces challenges in both areas.
11. The best way to address these challenges may differ among the regions, however. For example, in all regions the cost of the fuels used for electric generation has increased in recent years, as it has throughout the world. Those regions of the United States that depend on natural gas for electric generation have felt this the most. Competitive spot markets reflect these cost changes quickly in market prices, while longer-term fixed price bilateral contracts or cost-of-service regulation may reflect cost increases or decreases more gradually in the wholesale price
ased in recent years, as it has throughout the world. Those regions of the United States that depend on natural gas for electric generation have felt this the most. Competitive spot markets reflect these cost changes quickly in market prices, while longer-term fixed price bilateral contracts or cost-of-service regulation may reflect cost increases or decreases more gradually in the wholesale price. Wholesale customers in all regions want better long-term contracting opportunities. All regions face the problem that retail customers are often unaware of supply shortages and continue their normal consumption even on days when supplies are tight and wholesale prices are high. Allocating the costs of a major new regional transmission facility fairly is a challenge faced by every region.
12. Regions with an RTO or ISO may be better able than other regions to address some of these issues, but they may also face more difficult challenges. For example, much of the recent dissatisfaction with organized competitive markets appears to be directly linked to rising natural gas prices.
13. National policy is to promote wholesale competition in all regions, and customers now are calling especially for actions to improve the operation of wholesale competitive 6 The Commission seeks comment on proposed reforms to improve the operation of wholesale markets in these regions.
6 There are organized markets in the following 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 Service Operator Corp. (CAISO), Southwest Power Pool, Inc. (SPP), and the Electric Reliability Council of Texas (ERCOT).
A. Brief History
14. Numerous federal and state legislative and regulatory activities have supported competition in the U.S. electric industry over the last three decades
Transmission System Operator, Inc. (Midwest ISO), ISO New England, Inc. (ISO-NE), California Independent Service Operator Corp. (CAISO), Southwest Power Pool, Inc. (SPP), and the Electric Reliability Council of Texas (ERCOT).
A. Brief History
14. Numerous federal and state legislative and regulatory activities have supported competition in the U.S. electric industry over the last three decades. Congress enacted the Public Utility Regulatory Policies Act of 1978 (PURPA) 7 as a response to the energy crises of the 1970s. PURPA required electric utilities to interconnect with, and offer to purchase power from, qualifying cogeneration and small power production facilities at avoided cost rates set by state regulatory authorities. It gave the Commission limited authority to order wholesale transmission on a case-by-case basis, upon application by an eligible entity. A consequence of PURPA was the emergence of a new class of power generators that were independent of traditional utilities.
7 Pub. L. No. 95-617, 92 Stat. 3117 (codified in scattered sections of 15, 16, 26, 30, 42, and 43 U.S.C.) (1978).
15. Beginning in the 1980s, the Commission allowed independent power producers to sell electric energy at wholesale at negotiated rates instead of the traditional cost-based rates. 8 Development of a competitive generation sector was impeded, however, because independent power producers were discouraged from entering the generation business by certain provisions of the Public Utility Holding Company Act of 1935 (PUHCA) 9 and because the new power suppliers could not readily gain access to the transmission grid to reach wholesale buyers.
8 See The Electric Energy Market Competition Task Force, Report to Congress on Competition in Wholesale and Retail Markets for Electric Energy , Docket No. AD05-17-, at 22 (April 2007).
9 15 U.S.C. 79a et seq. (2000).
16. Congress addressed these problems in the Energy Policy Act of 1992 (EPAct 1992)
suppliers could not readily gain access to the transmission grid to reach wholesale buyers.
8 See The Electric Energy Market Competition Task Force, Report to Congress on Competition in Wholesale and Retail Markets for Electric Energy , Docket No. AD05-17-, at 22 (April 2007).
9 15 U.S.C. 79a et seq. (2000).
16. Congress addressed these problems in the Energy Policy Act of 1992 (EPAct 1992). 10 EPAct 1992 eased PUHCA restrictions so that independent and affiliate generators could more easily enter the market to compete at wholesale and it expanded the Commission's authority to order a transmitting utility to provide wholesale power transmission service, upon application on a case-by-case basis, to anyone selling power at wholesale. By the mid-1990s, the Commission found that ordering wholesale transmission services case-by-case did not adequately address problems with undue discrimination in transmission access, which limited opportunities for wholesale power competition. In 1996, the Commission used its authority under section 206 of the Federal Power Act (FPA) 11 to issue Order No. 888, remedying undue discrimination in access to transmission by requiring all public utilities with transmission to provide transmission service under an OATT. 12 The Commission recently issued Order No. 890 to remedy remaining opportunities for undue discrimination in the provision of open access transmission service.
10 Pub. L. No. 102-486, 106 Stat. 2776 (1992).
11 16 U.S.C. 824e (2000).
12 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., Regulations Preambles January 1991-June 1996 ¶ 31,036 (1996), order on reh'g , Order No. 888-A, FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,048 (1997), order on reh'g , Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g , Order No
transmission grid. Several ISOs—some based on longstanding power pools such as PJM and ISO-NE—formed after that. Early experience with open transmission access led the Commission to issue Order No. 2000 in December 1999, 14 which encouraged transmitting utilities, including those that were not public utilities, to join an RTO. 15 More than half the United States' load is now served by RTOs or ISOs. 16 Most RTOs and ISOs have adopted some forms of organized markets, which have continued to evolve with operating experience. 17 RTOs and ISOs have improved transmission reliability and enabled greater coordination and efficiency in the dispatch of resources and provision of transmission service over regions served previously by separate entities. Further, they have supported competitive power markets by eliminating pancaked rates in the region, as well as by providing a spot market to supplement traditional means of selling and buying power.
14 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).
15 See Order No. 2000, FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,089 at 31,028.
16 The Commission has approved RTOs or ISOs in several regions including the Northeast (PJM, NYISO, and ISO-NE), California (CAISO), the Midwest (Midwest ISO) and the Southwest (SPP).
17 RTOs and ISOs currently operate various combinations of the following organized markets: energy markets (day-ahead and real-time balancing markets), transmission rights, installed capacity markets, and other ancillary services markets.
19. While RTOs and ISOs have produced benefits, they also have encountered many challenges. Security constrained least cost dispatch over a large region can reveal transmission constraints and higher locational prices in constrained areas
zed markets: energy markets (day-ahead and real-time balancing markets), transmission rights, installed capacity markets, and other ancillary services markets.
19. While RTOs and ISOs have produced benefits, they also have encountered many challenges. Security constrained least cost dispatch over a large region can reveal transmission constraints and higher locational prices in constrained areas. Previously, average prices for the large region masked these constraints. Higher prices in certain locations and the lack of investment to relieve chronic congestion are criticisms of RTOs and ISOs. Concerns about transmission investment are common to both the RTO and ISO regions and the other regions.
20. Competitive wholesale markets for electric energy, including RTO and ISO spot markets, have had successes and failures. Competitive markets have stimulated generation investment, with much of the new generation supplied by merchant generating companies. 18 According to data from the Energy 19 A result has been to shift the risk of investment from customers to shareholders. In addition, under wholesale competition, the efficiency of existing nuclear, coal, and other types of generation has improved significantly, lowering costs to consumers and reducing environmental effects, and the increased capacity factors and availability of these units has further lowered electric generating costs. 20 The RTO and ISO-organized markets opened opportunities for renewable energy sources; an increasing fraction of new generation is from non-traditional sources such as wind generators. In fact, more wind generation has been added in RTO and ISO regions than in other regions, even though there are many areas with good wind availability. 21 RTO and ISO regions with organized markets report that competitive markets promote significant investment in new transmission, improve transmission reliability, and open new opportunities for demand response
nal sources such as wind generators. In fact, more wind generation has been added in RTO and ISO regions than in other regions, even though there are many areas with good wind availability. 21 RTO and ISO regions with organized markets report that competitive markets promote significant investment in new transmission, improve transmission reliability, and open new opportunities for demand response. 22
18 See Platts Research and Consulting/RDI, Review and Assessment of New Competitive-Market Sources of Power Generation (February 5, 2003); Paul L. Joskow February 27, 2007 Comments, Docket No. AD07-7-000; New England Power Generators Association, Inc., Meeting New England's Supply Needs: Regulated vs. Unregulated Generation, at http://www.nepga.org/contents/factsheet9041006.pdf.
19 U.S. Department of Energy, Energy Information Administration, Electric Power Annual 2005, Table 2.1 (November 2006), at http://www.eia.doe.gov/cneaf/electricity/epa/epat2p1.html.
20 North American Electric Reliability Corporation, Generating Availability Report (November 2006).
21 Michael Skelly February 27, 2007 Comments, Docket No. AD07-7-000, at 1 (submitted on behalf of Horizon Wind Energy and the American Wind Energy Association) (reporting that “[w]ell-structured regional wholesale electricity markets operated independently allow far greater amounts of renewable energy and demand response resources to be integrated into the nation's electric grid. In fact, approximately 73 percent of installed wind capacity is now located in regions with such markets, while only 44 percent of wind energy potential is found in these areas. Large, regional energy markets provide for cost-effective balancing of generation and load with significant penetrations of variable, nondispatchable power sources, and they facilitate delivery of resources remote from load centers.”)
22 See, e.g. , ISO/RTO Council, The Value of Independent Regional Grid Operators (November 2005), http://www.caiso.com/14c6/14c6c4291aa40.pdf.
21
in these areas. Large, regional energy markets provide for cost-effective balancing of generation and load with significant penetrations of variable, nondispatchable power sources, and they facilitate delivery of resources remote from load centers.”)
22 See, e.g. , ISO/RTO Council, The Value of Independent Regional Grid Operators (November 2005), http://www.caiso.com/14c6/14c6c4291aa40.pdf.
21. Despite all of the successes attributable to wholesale competition, there have been difficulties. The most prominent is that spot markets in California during 2000 and 2001 experienced sustained high wholesale prices resulting from supply shortages, market design flaws, and market abuses. In other RTOs and ISOs, prices in the day-ahead and real-time balancing markets have been volatile at times. This volatility can present issues for both buyers and sellers as buyers try to hedge the volatility and sellers try to project revenues from the organized markets. Even with the volatility, the RTO and ISO markets have provided wholesale customers and suppliers with a new and constantly available opportunity to buy or sell power and transparent price information.
22. Much of the concern about competition in wholesale power markets can be traced to the effects of higher natural gas prices on wholesale electric power prices. As the Commission's staff reports, “natural gas currently functions as the most significant price-setting fuel in U.S. electric generation.” 23 Natural gas prices have increased significantly over the last decade. According to the Energy Information Administration, the average U.S. wellhead price of natural gas increased from $2.17 in 1996 to $6.42 in 2006 (which was down from $7.33 in 2005). 24 The summer 2007 futures prices from the New York Mercantile Exchange (NYMEX) for natural gas at Henry Hub, Louisiana are up 21 percent over last summer's actual average prices traded on the Intercontinental Exchange (ICE)
ing to the Energy Information Administration, the average U.S. wellhead price of natural gas increased from $2.17 in 1996 to $6.42 in 2006 (which was down from $7.33 in 2005). 24 The summer 2007 futures prices from the New York Mercantile Exchange (NYMEX) for natural gas at Henry Hub, Louisiana are up 21 percent over last summer's actual average prices traded on the Intercontinental Exchange (ICE). 25 As reported by Commission staff, wholesale prices for electricity are expected to be higher in the summer of 2007 in all regions of the United States, regardless of regional market structure. 26 The principal reason is higher expected prices for natural gas. As the United States has increased its reliance on natural gas for electricity generation, particularly to meet peak loads, the forward price of natural gas has had an increasing effect on the forward price of wholesale electric power, especially during electric peak periods. The effect of wholesale prices is felt in parts of the United States that have no organized markets as well as regions with organized markets.
23 Stephen Harvey, Office of Enforcement, Federal Energy Regulatory Commission, Presentation at the May 17, 2007 Commission Meeting: 2007 Summer Energy Market Assessment (May 17, 2007) (Summer Market Assessment), at http://www.ferc.gov/EventCalendar/Files/20070517112506-A-3.pdf [to fix].
24 See Id. See also U.S. Department of Energy, Energy Information Administration, U.S. Natural Gas Wellhead Price, at http://tonto.eia.doe.gov/dnav/ng/hist/n9190us3a.htm.
25 See Summer Market Assessment. These NYMEX and ICE prices are not estimates but prices actually produced on those two trading systems.
26 Id.
23. Some perceived challenges in the organized wholesale markets may be closely related to difficulties in state retail choice programs. Retail choice programs tend to be in areas served by organized wholesale markets, and the distinction between wholesale and retail competition challenges is often blurred
ices are not estimates but prices actually produced on those two trading systems.
26 Id.
23. Some perceived challenges in the organized wholesale markets may be closely related to difficulties in state retail choice programs. Retail choice programs tend to be in areas served by organized wholesale markets, and the distinction between wholesale and retail competition challenges is often blurred. It appears that some areas with retail choice depend on their RTO or ISO to provide or arrange for the provision of some functions previously carried out by vertically integrated utilities. This has created challenges for wholesale market design, particularly with regard to whether it effectively provides for resource adequacy. Because wholesale and retail markets are intertwined, any examination of retail choice typically involves a critique of the combination of the particular retail choice program and the RTO's or ISO's wholesale market design.
24. The Commission continues to believe that wholesale competition benefits customers by providing more choice, spurring innovative services and technologies, shifting risk away from customers, improving efficiency, and providing incentives for cost reductions and for the construction of new resources. As stated above, the purpose of this ANOPR is to explore reasonable proposals for improving wholesale organized markets.
B. Competition Issues and Commission Actions
25. In proceedings outside this ANOPR, the Commission has addressed or is addressing many issues related to improving wholesale electric power competition in all regions, both with and without organized markets. The Commission has taken actions to improve wholesale transmission and competitive wholesale power opportunities.
26. The Commission's transmission actions have included reform of the OATT, development of long-term transmission rights policies, incentives for new transmission infrastructure, and approval of transmission cost allocation policies
l regions, both with and without organized markets. The Commission has taken actions to improve wholesale transmission and competitive wholesale power opportunities.
26. The Commission's transmission actions have included reform of the OATT, development of long-term transmission rights policies, incentives for new transmission infrastructure, and approval of transmission cost allocation policies. OATT reform applies to transmission-owning and operating public utilities in all regions. It adds greater consistency and transparency to available transfer capability calculations, requires an open and coordinated regional transmission planning process, and reforms energy imbalance charges. Additionally, it provides for a new “conditional firm” point-to-point transmission service. Long-term transmission rights in RTOs and ISOs were strengthened in Order Nos. 681 and 681-A. These orders, as directed by EPAct 2005, provide for long-term transmission price certainty in the organized electricity markets, which supports long-term power supply arrangements. In Order No. 679, 27 the 28 This rule allows those building transmission to apply for recovery of prudently incurred costs for construction work in progress, pre-operations, and abandoned facilities, and it provides for application for an incentive rate of return on equity for new transmission investment. To further encourage transmission investment, and provide certainty about who pays for new transmission, the Commission, in separate orders for each RTO or ISO—including two this year 29 —has approved cost allocation policies for new and existing transmission, thereby removing any barrier to new investment caused by uncertainty about transmission cost allocation.
27 Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43,294 (July order on reh'g, Order No. 679-A, 72 FR 1,152 (January 10, 2007), FERC Stats. & Regs. ¶ 31,236 (2006), order on reh'g, 119 FERC ¶ 61,062 (2007)
allocation policies for new and existing transmission, thereby removing any barrier to new investment caused by uncertainty about transmission cost allocation.
27 Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43,294 (July order on reh'g, Order No. 679-A, 72 FR 1,152 (January 10, 2007), FERC Stats. & Regs. ¶ 31,236 (2006), order on reh'g, 119 FERC ¶ 61,062 (2007).
28 Section 1241 of EPAct 2005 is to be codified at section 219 of the FPA, 16 U.S.C. 824s.
29 PJM Interconnection, L.L.C., Opinion No. 494, 119 FERC ¶ 61,063 (2007), reh'g pending (approving PJM's cost allocation proposal for existing transmission facilities, and requiring revisions to its proposal for new transmission facilities); Midwest Independent Transmission System Operator, Inc., 118 FERC ¶ 61,209 (2007), reh'g pending (conditionally approving cost allocation for economic upgrades). In 2006, the Commission approved the Midwest ISO's proposed cost allocation for reliability upgrades. Midwest Independent Transmission System Operator, Inc., 114 FERC ¶ 61,106, order on technical conference, 117 FERC ¶ 61,241 (2006), order on reh'g, 118 FERC ¶ 61,208 (2007), reh'g pending.
27. The Commission also has undertaken numerous actions in support of competitive wholesale power opportunities. For example, the Commission established interconnection rules for large, small and wind generators. In addition, the Commission has not only granted initial approval to the organized markets of the RTO and ISO regions but has continued to work with each region to improve the design of its markets as the region and the Commission have gained experience with the different regional approaches. Further, we have approved various market power mitigation rules and provided for market monitoring in the organized markets of RTOs and ISOs. Also, in response to EPAct 2005, the Commission prepared a report that assesses electric demand response resources by region
to improve the design of its markets as the region and the Commission have gained experience with the different regional approaches. Further, we have approved various market power mitigation rules and provided for market monitoring in the organized markets of RTOs and ISOs. Also, in response to EPAct 2005, the Commission prepared a report that assesses electric demand response resources by region. 30 The Commission has also opened a proceeding on demand response in wholesale markets, and we held a technical conference on April 23, 2007, to examine demand resources in markets, grid operations and expansion, and best practices for the measurement and evaluation of demand response resources. 31 These Commission actions, along with other prior actions of the Commission, are intended to work together to improve the operation of competitive wholesale markets across the nation, in regions with and without organized markets. The proposals in this ANOPR complement these actions and are part of our ongoing effort to maintain and encourage competitive wholesale electric energy markets.
30 Federal Energy Regulatory Commission, Assessment of Demand Response and Advanced Metering: Staff Report, Docket No. AD06-2-000 (August 8, 2006) ( FERC Staff Demand Response Assessment).
31 See Supplemental Notice, Demand Response in Wholesale Markets, Docket No. AD07-11-000 (April 6, 2007).
28. With the passage of EPAct 2005, Congress granted the Commission additional authorities to support wholesale competition. Key provisions in EPAct 2005 include authority to impose civil penalties for market manipulation, to prevent exercise of market power through expanded power to review mergers and generation facility transfers, and to require market transparency
AD07-11-000 (April 6, 2007).
28. With the passage of EPAct 2005, Congress granted the Commission additional authorities to support wholesale competition. Key provisions in EPAct 2005 include authority to impose civil penalties for market manipulation, to prevent exercise of market power through expanded power to review mergers and generation facility transfers, and to require market transparency. EPAct 2005 also included a number of provisions designed to strengthen the interstate power grid, both to assure reliability and support competitive markets, encouraging the Commission to increase transmission investment through incentives, providing for backstop federal siting of transmission facilities, encouraging the deployment of advanced technologies, and authorizing the Commission to approve and enforce mandatory reliability standards. The Commission has taken these and other new responsibilities seriously and has complied with all Congressional directives and deadlines.
29. In addition, the Commission has recognized that there are issues that need to be addressed where the Commission and state commissions share an interest, such as demand response and competitive procurement. The Commission is engaged with the National Association of Regulatory Utility Commissioners (NARUC) in two collaborative efforts, the NARUC-FERC Collaborative Dialogue on Demand Response and the NARUC-FERC Competitive Procurement Collaborative.
C. Issues Addressed in the ANOPR
30. Competition remains national policy with respect to wholesale power markets. Competition continues to be sound policy in wholesale markets, when combined with effective regulation. The Commission has a duty to improve the operation of wholesale power markets to support competition. One way to accomplish that is by pursuing regulatory reform
t Collaborative.
C. Issues Addressed in the ANOPR
30. Competition remains national policy with respect to wholesale power markets. Competition continues to be sound policy in wholesale markets, when combined with effective regulation. The Commission has a duty to improve the operation of wholesale power markets to support competition. One way to accomplish that is by pursuing regulatory reform. To that end, the Commission initiated this proceeding, designed to identify the challenges facing competitive wholesale power markets, identify workable solutions to those challenges that will complement other Commission actions to improve the operation of competitive wholesale markets, and determine which solutions are within the Commission's authority. This proceeding also responds to concerns raised by market participants regarding needed improvements to the operation of competitive wholesale markets.
31. In order to gather more information and allow public comment, the Commission held a conference on competition issues on February 27, 2007. At this first competition conference, most speakers addressed issues affecting the RTO and ISO regions, including the level of wholesale prices, the need for long-term power contracts, the effectiveness of market monitoring, and the lack of adequate demand response. The Commission held a second competition conference on May 8, 2007, to examine in more detail several specific concerns and challenges identified in the first conference. This second conference focused on regions with RTOs and ISOs and organized markets and dealt with: (1) Demand response and market prices during a power shortage; (2) fostering long-term power contracting; and (3) the responsiveness of RTOs and ISOs to customers and other stakeholders
May 8, 2007, to examine in more detail several specific concerns and challenges identified in the first conference. This second conference focused on regions with RTOs and ISOs and organized markets and dealt with: (1) Demand response and market prices during a power shortage; (2) fostering long-term power contracting; and (3) the responsiveness of RTOs and ISOs to customers and other stakeholders. The panel on demand response emphasized allowing customers to respond to high prices, particularly when generating capacity falls short of demand, providing adequate compensation for demand reductions, and allowing many small retail demand reductions to be aggregated for use in the wholesale power market. The panel on long-term power contracting discussed the role and availability of long-term contracts, as well as the importance of long-term transmission service and a robust transmission system. The RTO and ISO accountability panel discussed the need for RTOs and ISOs to be more responsive to their stakeholders; it considered several means of achieving this such as allowing a few stakeholder representatives to serve on hybrid boards of RTOs or ISOs. On April 5, 2007, the Commission also held a technical conference on market monitoring policies and heard from interested commenters on issues such as the development of the concept and
32. Based on comments received at these three conferences, the Commission decided to consider in this ANOPR four issues in organized market regions that are not already being fully addressed by the Commission in other proceedings. These areas are: (1) The role of demand response in organized markets and greater use of market prices to elicit demand reductions during a power shortage; (2) increasing opportunities for long-term power contracting; (3) strengthening market monitoring; and (4) enhancing the responsiveness of RTOs and ISOs to customers and other stakeholders.
33
addressed by the Commission in other proceedings. These areas are: (1) The role of demand response in organized markets and greater use of market prices to elicit demand reductions during a power shortage; (2) increasing opportunities for long-term power contracting; (3) strengthening market monitoring; and (4) enhancing the responsiveness of RTOs and ISOs to customers and other stakeholders.
33. At this time, the Commission is not addressing in this ANOPR potential reforms outside the organized market regions. As discussed in our first technical conference, the primary concerns of wholesale customers and competitors in other regions are nondiscriminatory access to transmission and nondiscriminatory rules for power procurement. These two areas, although critically important, are being addressed by the Commission in other proceedings. In Order No. 890, the Commission reformed the OATT to ensure that it continues to provide nondiscriminatory access to transmission service. Much work remains to be done, however, and the Commission is focusing on the compliance phase of OATT reform to ensure that it is implemented properly, particularly in the area of regional transmission planning and the calculation of available transfer capability. With regard to power procurement, the Commission believes that competitive procurement can enhance the ability of LSEs to acquire reliable wholesale power supplies at reasonable prices. The Commission recognizes, however, that wholesale power procurement raises issues that are important to both the Commission and state commissions. The Commission is therefore pursuing a cooperative dialogue with NARUC to develop guidelines for best practices for power procurement. Since these two main areas of concern are being pursued in other proceedings, the Commission will not address reforms outside the RTO/ISO regions in this proceeding. Similarly, issues related to demand response are important to both this Commission and state commissions
ommission is therefore pursuing a cooperative dialogue with NARUC to develop guidelines for best practices for power procurement. Since these two main areas of concern are being pursued in other proceedings, the Commission will not address reforms outside the RTO/ISO regions in this proceeding. Similarly, issues related to demand response are important to both this Commission and state commissions. Concerns with participation of demand response in organized and bilateral markets were voiced in our technical conferences. The Commission is pursuing a collaborative dialogue with state commissions on best practices and coordination on demand response issues, and lessons learned there may be applicable to bilateral markets.
III. Demand Response and Pricing During Power Shortages in Organized Markets
34. A well-functioning competitive wholesale electric market should reflect current supply and demand conditions. The Commission has expressed the view on numerous occasions that the wholesale electric power market works best when demand can respond to the wholesale price. 32 The Commission's policy is to facilitate the participation of demand response in the organized power markets, in part because demand response helps to hold down wholesale power prices, increases awareness of energy usage, provides for more efficient operation of markets, mitigates market power, and enhances reliability. This policy reflects the Commission's view that the value of electric power to customers is not always the same. It changes over time and varies from place to place. The value can be very different for two customers at the same time and place, one of whom may prefer to reduce consumption if the price is high and another who may be willing to pay a high price to avoid curtailment in an emergency
y. This policy reflects the Commission's view that the value of electric power to customers is not always the same. It changes over time and varies from place to place. The value can be very different for two customers at the same time and place, one of whom may prefer to reduce consumption if the price is high and another who may be willing to pay a high price to avoid curtailment in an emergency.
32 New England Power Pool and ISO New England, Inc., 101 FERC ¶ 61,344, at P 44-49 (2002), order on reh'g, 103 FERC ¶ 61,304, order on reh'g, 105 FERC ¶ 61,211 (2003); PJM Interconnection, L.L.C., 95 FERC ¶ 61,306 (2001); PJM Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002); Southwest Power Pool, Inc., 116 FERC ¶ 61,289 (2006).
35. While the Commission and the various RTOs and ISOs have done much to facilitate demand response in organized power markets, more can be done. In response to a requirement of EPAct 2005 to assess demand response capability nationally, the August 2006 FERC Staff Demand Response Assessment estimated the total installed demand response capability from existing programs nationally to be 37,500 megawatts (MW), or about five percent of current peak demand. Several reports indicate that the potential demand response capability available in the United States may be much greater than this. 33 The Commission's preliminary view is that RTO and ISO wholesale market design changes or additions, particularly for energy and ancillary services markets, may be needed to help tap that potential. Our goal is for RTOs and ISOs to develop rules to ensure the treatment of supply and demand resources on a comparable basis to the extent each is technically capable of providing the service. Our aim is not to afford demand resources preferential treatment over supply resources
n changes or additions, particularly for energy and ancillary services markets, may be needed to help tap that potential. Our goal is for RTOs and ISOs to develop rules to ensure the treatment of supply and demand resources on a comparable basis to the extent each is technically capable of providing the service. Our aim is not to afford demand resources preferential treatment over supply resources. For example, even under the mechanisms contemplated by this ANOPR, demand resources must satisfy all requirements for service provision comparable to those applied to supply resources, including but not limited to procedures for measurement and verification of performance, as well as penalties. Further, our aim is not to require demand resources to participate in these or any other resource programs. Rather, we are merely ensuring that the wholesale markets are designed to accommodate demand resources in a manner comparable to supply resources, unless not permitted by state law. Therefore, the mechanisms should not intrude on state jurisdiction. The Commission's proposals do not require action by states but can benefit from such action.
33 See, e.g. , Ahmad Faruqui et al. , The Brattle Group, The Power of Five Percent: How Dynamic Pricing Can Save $35 Billion in Electricity Costs (May 16, 2007), http://www.brattle.com/_documents/Publications/ArticleReport2441.pdf.
A. Importance of Demand Response to Competition in RTO/ISO Areas
36. The value of demand response to properly functioning RTO and ISO markets has been described in detail by many experts, such as Nobel Prize-winning economist Vernon Smith and Lynne Kiesling, in their paper titled “A Market-Based Model for ISO-Sponsored Demand Response Programs.” 34 Demand response assists competitive wholesale markets in at least three ways.
34 Vernon Smith and Lynne Kiesling, Market-Based Model for ISO-Sponsored Demand Response Programs, (September 2005), http://www.defgllc.com/Downloads/051018_DEFG_DRwp02.pdf .
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nning economist Vernon Smith and Lynne Kiesling, in their paper titled “A Market-Based Model for ISO-Sponsored Demand Response Programs.” 34 Demand response assists competitive wholesale markets in at least three ways.
34 Vernon Smith and Lynne Kiesling, Market-Based Model for ISO-Sponsored Demand Response Programs, (September 2005), http://www.defgllc.com/Downloads/051018_DEFG_DRwp02.pdf .
37. First, demand response can help reduce wholesale prices and wholesale price volatility. The reduction is valued especially during peak periods, but demand response can also lower price and volatility during off-peak periods. Demand response can lower wholesale prices directly and indirectly. The direct effect occurs when a demand reduction is bid directly into the wholesale market: lower demand means a lower wholesale price. Demand response at retail, if not bid directly into the wholesale market by a large retail customer, affects the wholesale market indirectly because it reduces the need for power by the retail customers' LSE and in turn reduces that LSE's need to purchase power from the wholesale market. For example, where an LSE offers retail customers some form of
38. Second, demand response tends to flatten an area's load profile. With a flatter load profile, the distribution of generation types tends to shift toward lower-cost base load generation and away from higher-cost peaking generation, and this tends to lower the overall average cost to produce energy.
39. Third, demand response can help reduce the potential for market manipulation by reducing generator market power. As more demand response is available during peak periods, power suppliers need to account more for the price responsiveness of load when they consider higher-price bids. The more demand response is able to reduce the peak price, 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 too high.
40
t power. As more demand response is available during peak periods, power suppliers need to account more for the price responsiveness of load when they consider higher-price bids. The more demand response is able to reduce the peak price, 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 too high.
40. RTOs such as PJM, NYISO, and ISO-NE have quantified the cost-effectiveness of demand response in their wholesale markets. They assessed both the reduction in market prices due to demand reductions and the value of demand response to system reliability. These assessments conclude that the demand response programs they operate produce net benefits associated with lower wholesale prices. For example, ISO-NE found that the benefits of its various economic and emergency demand response programs in 2005 more than compensate for its costs, largely payments to demand response participants and its own extra operating costs. 35 PJM and NYISO found similar positive results in evaluations of their programs. 36
35 ISO-NE, An Evaluation of the Performance of the Demand Response Programs Implemented by ISO-NE in 2005, Docket No. ER02-2330-040 (Dec. 30, 2005).
36 NYISO, NYISO 2006 Demand Response Programs, Docket No. ER01-3001-016 (Feb. 16, 2007); PJM, Assessment of PJM Load Response Programs, Docket No. ER02-1326-006 (Aug. 29, 2006).
B. Prior Commission Actions To Address Demand Response
41. The Commission has issued numerous orders over the last several years on various aspects of electric demand response in organized markets. A goal of most of these orders was to remove unnecessary obstacles to demand response participating in the wholesale power markets of RTOs and ISOs
rograms, Docket No. ER02-1326-006 (Aug. 29, 2006).
B. Prior Commission Actions To Address Demand Response
41. The Commission has issued numerous orders over the last several years on various aspects of electric demand response in organized markets. A goal of most of these orders was to remove unnecessary obstacles to demand response participating in the wholesale power markets of RTOs and ISOs. 37
37 See, e.g., New York Independent System Operator, Inc., 92 FERC ¶ 61,073, order on clarification, 92 FERC ¶ 61,181 (2000), order on reh'g, 97 FERC ¶ 61,154 (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, L.L.C., 95 FERC ¶ 61,306 (2001); PJM Interconnection, L.L.C., 99 FERC ¶ 61,139 (2002); PJM Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002).
42. 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, 38 programs to allow wholesale buyers and qualifying large retail buyers to bid a demand reduction directly into the day-ahead and real-time energy markets and certain ancillary service markets, particularly as a provider of operating reserves, as well as programs to accept bids from aggregators of retail customers (ARCs). 39 The Commission also has approved special demand response applications such as use of demand response for synchronized reserves and regulation service. 40 The theme underlying the Commission's approval of these programs has been to allow demand resources to participate in these markets on a basis that is comparable to other resources.
38 See, e.g. , PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006); Devon Power L.L.C., 115 FERC ¶ 61,340 (2006). These orders allow demand resources to provide capacity resources
eserves and regulation service. 40 The theme underlying the Commission's approval of these programs has been to allow demand resources to participate in these markets on a basis that is comparable to other resources.
38 See, e.g. , PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006); Devon Power L.L.C., 115 FERC ¶ 61,340 (2006). These orders allow demand resources to provide capacity resources.
39 We will use the phrase “aggregation of retail customers” to refer to RTOs and ISOs accepting bids from parties that aggregate demand response bids (which are mostly from retail loads), or ARCs. See, e.g., New York Independent System 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, L.L.C., 99 FERC ¶ 61,227 (2002).
40 See, e.g., PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 (2006).
43. An important type of demand response program is one that allows demand response bids in the day-ahead and real-time energy markets by a group of retail customers. There is usually a minimum size bid allowed in an RTO or ISO market for any participating retail customer. The Commission has approved programs that allow smaller retail customers to combine their individual demand reductions into a larger block for bidding into the organized markets, if permitted by state law, without having to go through their LSE. 41 A third party ARC, often called a curtailment service provider, typically provides this aggregation service. The aggregate demand reduction may be bid directly into the energy and ancillary services markets
retail customers to combine their individual demand reductions into a larger block for bidding into the organized markets, if permitted by state law, without having to go through their LSE. 41 A third party ARC, often called a curtailment service provider, typically provides this aggregation service. The aggregate demand reduction may be bid directly into the energy and ancillary services markets.
41 See, e.g., New York Independent System 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, L.L.C., 99 FERC ¶ 61,227 (2002).
44. In addition, the Commission has explicitly addressed demand response in its recent final rules on OATT Reform (Order No. 890) and reliability standards (Order No. 693). 42 Order No. 890 requires any public utility with an OATT to allow qualified demand resources to participate in its regional transmission planning process on a comparable basis and to allow qualified demand response to provide certain ancillary services. Specifically, we agreed with a request by Alcoa that load resources ( i.e. , demand response) should be permitted to self-supply and sell ancillary services to third parties. 43 In doing so, we also made clear that a Transmission Provider may use non-generation resources in meeting its OATT obligation to provide ancillary services, so long as those resources are capable of providing the service. 44 Order No. 890 did not require Transmission Providers to purchase ancillary services from non-generation resources or generation resources. Our proposal here would require RTO/ISO ancillary service markets to allow bidding by non-generation resources if they are capable of providing such services. Order No
ovide ancillary services, so long as those resources are capable of providing the service. 44 Order No. 890 did not require Transmission Providers to purchase ancillary services from non-generation resources or generation resources. Our proposal here would require RTO/ISO ancillary service markets to allow bidding by non-generation resources if they are capable of providing such services. Order No. 693 requires the Electricity Reliability Organization to revise its reliability standards so that all technically feasible resource options, including demand response and generating resources, may be employed in the management of grid operations and emergencies. 45
42 See Mandatory Reliability Standards for the Bulk Power System, Order No. 693, 72 FR 16,416 (April 4, 2007), FERC Stats. & Regs. ¶ 31,242 (2007).
43 Order No. 890 at P 887-88.
44 E.g., Order 890, OATT Schedule 5 (Operating Reserve—Spinning Reserve Service).
45 Order No. 693 directed the Electricity Reliability Organization to develop new versions of its BAL-002, BAL-005, and EOP-002 reliability standards to allow demand side resources to provide contingency reserves. Order No. 693 at ¶ 330-35, 404-06, 573.
45. The Commission has also encouraged demand response outside of its orders. The Commission has conducted several technical conferences on demand response over the last several years, most recently on April 23, 2007. 46 The NARUC-FERC 47
46 For example, the Commission conducted a technical conference on January 25, 2006 to support the FERC Staff Demand Response Assessment in Docket No. AD06-2-000. The April 23, 2007 conference was convened in Docket No. AD07-11-000.
47 See FERC Staff Demand Response Assessment.
46. In this ANOPR, the Commission's focus is on exploring market rules that allow both wholesale and qualifying retail customers to bid demand response into the day-ahead, real-time energy, and ancillary services markets.
C. Remaining Problems With Demand Response in Organized Markets
47
, 2007 conference was convened in Docket No. AD07-11-000.
47 See FERC Staff Demand Response Assessment.
46. In this ANOPR, the Commission's focus is on exploring market rules that allow both wholesale and qualifying retail customers to bid demand response into the day-ahead, real-time energy, and ancillary services markets.
C. Remaining Problems With Demand Response in Organized Markets
47. While progress has been made to increase demand-responsiveness and price-responsiveness in organized markets, more needs to be done.
48. An effective way for demand to respond to price is at the retail level, through some form of time-based retail rates (time-based retail rates include rates that vary by hour, such as real-time pricing, or by blocks of time, such as time-of-use rates or critical peak pricing). Demand response is more effective when retail rates are tied to current wholesale market-clearing prices. Effective demand response can be achieved by linking the wholesale and retail markets. While the Commission can remove some obstacles to demand participation in organized markets, more effective demand response also requires the action of state commissions.
49. As discussed in the FERC Staff Demand Response Assessment, some forms of demand response are well-suited to provide the ancillary services of spinning reserves, supplemental reserves, energy imbalance, and regulation and frequency response. 48 Because demand is always connected and demand reduction, in principle, can always be available, some forms of demand resources may be able to provide a rapid, near real-time response. 49 Nevertheless, except for a few markets, demand response is not able to participate in these ancillary services markets. ISO-NE, NYISO, and CAISO allow demand resources to provide supplemental (non-spinning) reserves
cause demand is always connected and demand reduction, in principle, can always be available, some forms of demand resources may be able to provide a rapid, near real-time response. 49 Nevertheless, except for a few markets, demand response is not able to participate in these ancillary services markets. ISO-NE, NYISO, and CAISO allow demand resources to provide supplemental (non-spinning) reserves. As of mid-2007, only PJM allows demand resources to provide synchronized reserves (PJM's term for spinning reserves) and regulation service (although no resource has yet qualified to provide this service in PJM).
48 For an explanation of each of these ancillary services, see the pro forma OATT, Schedules 3 through 6, contained in Order No. 890.
49 For example, electric-arc steel furnaces have the capability to adjust their consumption rapidly, and air conditioner cycling programs can respond within several minutes of execution.
50. Several factors may account for the lack of participation of demand resources in some ancillary services markets. System operators responsible for maintaining reliable operation have little or no experience with the responsiveness of demand resources and may lack confidence in them. To qualify to provide ancillary services, a resource must satisfy certain requirements such as having a minimum size 50 and real-time telemetry. These requirements can limit which customers may participate and may also obligate customers to invest in real-time metering and monitoring equipment at their sites.
50 ISO-NE places a minimum size of 5 MW for participation. See ISO-NE, ISO New England Manual for Market Rule 1 Accounting (May 31, 2007), at section 12.3.5.3, http://www.iso-ne.com/rules_proceds/isone_mnls/m_28_market_rule_1_accounting_(revision_27)_05_31_07.doc.
51. In addition, market rules for bidding and participating in ancillary services markets were developed with generation in mind and may not make sense for demand response resources
icipation. See ISO-NE, ISO New England Manual for Market Rule 1 Accounting (May 31, 2007), at section 12.3.5.3, http://www.iso-ne.com/rules_proceds/isone_mnls/m_28_market_rule_1_accounting_(revision_27)_05_31_07.doc.
51. In addition, market rules for bidding and participating in ancillary services markets were developed with generation in mind and may not make sense for demand response resources. Distinguishing among rules that must apply to all resources to maintain reliability and those that can be amended to accommodate inflexible or special case resources is an important market design issue. For example, many demand resources can respond quickly and at a low cost if called on for a short duration, which may make them well suited for providing operating reserves. A large industrial customer, such as a steel mill, provides an operating reserve when it reduces its load quickly within seconds or minutes, in response to direction from a system operator. However, if market rules require that bids be made into a joint energy-plus-reserves market, those offering operating reserves must also be available to provide energy or other ancillary services. The result is that the operating reserve provider that risks being called on frequently or for a prolonged period in the energy market may simply decide not to participate in the energy market, and consequently not provide demand reduction as operating reserves. Because energy use is necessary to a customer's business, frequent or lengthy unplanned interruptions could disrupt that business. As a result, market rules that do not allow a demand response provider to limit the frequency and duration of interruption creates a disincentive for a demand resource to bid into the operating reserves market. 51
51 See FERC Staff Demand Response Assessment at 123.
52. Demand response providers need market rules that allow bids to be flexible and that reflect bidders' willingness to offer various levels of service depending on the market prices
response provider to limit the frequency and duration of interruption creates a disincentive for a demand resource to bid into the operating reserves market. 51
51 See FERC Staff Demand Response Assessment at 123.
52. Demand response providers need market rules that allow bids to be flexible and that reflect bidders' willingness to offer various levels of service depending on the market prices. In fact, the design of today's organized markets does allow some flexible and some price-sensitive bidding into day-ahead and real-time energy markets. Nevertheless, the Commission is concerned that some market features may inhibit LSEs and other demand response providers from bidding load reductions into energy markets. For example, in most organized markets, if an LSE's actual purchase from the real-time market differs from the purchase it scheduled in the day-ahead market, it may be assessed an uplift charge (separate from any imbalance charge) 52 While it is important to have mechanisms in place that encourage LSEs to accurately forecast and schedule their loads in the day-ahead market, these types of charges may unnecessarily discourage an LSE from urging retail customers to conserve energy during a system emergency.
52 During reserve shortages on August 1 in the Midwest ISO region, LSEs contributed close to 3,000 MW of demand reductions but were assessed revenue sufficiency guarantee charges—charges that ensure that any generator scheduled or dispatched by the Midwest ISO after the close of the day-ahead energy market will receive no less than its offer prices for start-up, no-load and incremental energy. Wisconsin Public Service Commission Chairperson Daniel Ebert reported on these charges at the April 23, 2007 technical conference on demand response. See Technical Conference on Demand Response in Wholesale Markets on April 23, 2007, Tr. 83-84 (Daniel Ebert, Wisconsin Public Service Commission) (Docket No. AD07-11-000).
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less than its offer prices for start-up, no-load and incremental energy. Wisconsin Public Service Commission Chairperson Daniel Ebert reported on these charges at the April 23, 2007 technical conference on demand response. See Technical Conference on Demand Response in Wholesale Markets on April 23, 2007, Tr. 83-84 (Daniel Ebert, Wisconsin Public Service Commission) (Docket No. AD07-11-000).
53. Organized energy market rules may restrict the type of bid that a LSE or ARC may submit. In some cases, this may be intended to treat a demand response bid the same as a generation bid, but, in other cases there may be a restriction on a demand response bid that does not apply to a generation bid. Bidding features available to generation, such as a guaranteed minimum price and a minimum duration of service, are often not available to demand reductions. Some generators need such features if, for example, they are not able to start and stop frequently or if cycling output up and down produces excessive stress on their equipment. Providers of demand reductions may have their own limitations on cycling but not be allowed to express these in their bids. For example, if a factory reduces consumption in response to a dispatch signal, it may be required to stop production for an entire work shift
54. As mentioned above, the Commission has approved some demand response programs that allow retail customers, if it is consistent with state law, to bid their combined demand reductions through an ARC into wholesale day-ahead and real-time markets. PJM, ISO-NE and NYISO have allowed such ARCs to become market participants, and these RTOs accept bids from ARCs. 53 If these load reduction bids are accepted, the RTO or ISO directs the customers to reduce their consumption as bid and the customers are paid the market-clearing price
h state law, to bid their combined demand reductions through an ARC into wholesale day-ahead and real-time markets. PJM, ISO-NE and NYISO have allowed such ARCs to become market participants, and these RTOs accept bids from ARCs. 53 If these load reduction bids are accepted, the RTO or ISO directs the customers to reduce their consumption as bid and the customers are paid the market-clearing price. The aggregation of retail customers programs in PJM and ISO-NE allow program participants to reduce their demand before the real-time market runs without being subject to uplift charges for unscheduled changes from the day-ahead schedule.
53 These aggregation of retail customers programs go by various names. PJM operates the Economic Load Response Program that allows direct bidding in day-ahead and real-time markets. NYISO operates the Day-Ahead Demand Response Program. ISO-NE operates the Day-Ahead Load Response Program and the Real-Time Price Response Program.
55. Another factor that may limit participation by LSEs and retail customers in demand response programs is the use of bid caps and price caps in the market design. Bid caps and price caps in RTO and ISO markets are designed to limit the opportunity to exercise market power in these markets, but they also may prevent the markets from expressing prices that are legitimately high due to a shortage. These caps may not permit buyers in RTO and ISO wholesale energy markets to see prices high enough to signal that there is a power shortage and reliability is at risk. Moreover, when power is in short supply and price is high, retail prices remain fixed, and retail customers do not adjust their demand to react to wholesale price signals because these price signals are not seen. Consequently, both generation and demand response can be in short supply at once, and the market-clearing price may not reflect the actual cost of providing more power or the value to customers of not being interrupted
t supply and price is high, retail prices remain fixed, and retail customers do not adjust their demand to react to wholesale price signals because these price signals are not seen. Consequently, both generation and demand response can be in short supply at once, and the market-clearing price may not reflect the actual cost of providing more power or the value to customers of not being interrupted. Further, as discussed in the long-term contracting section below, capping the exposure of LSEs to higher prices may reduce their incentive to explore various hedging activities, such as participating in interruptible demand response programs, entering into long-term contracts or similar power supply procurement options, and building new generating units.
56. Certain demand response programs may themselves act to dampen prices during a power shortage. Emergency demand response programs are those intended to ensure reliability, which are called on by RTOs and ISOs only during a system emergency. They may be paid a fixed price such as $500 per MWh when called on. Typically, these emergency resources are not paid the market-clearing price. As a result, the market-clearing price may decrease because demand is reduced when an emergency demand response resource is used, even though it is the highest-valued resource used at the time. The reduced price signals that buyers should consume more and suppliers produce less, which is contrary to the signal that should be sent in an emergency. Only NYISO has integrated its emergency demand response programs into the market-clearing process, 54 and Midwest ISO is discussing a similar integration based on its 2006 experience.
54 The Commission approved this change in 2003. New York Independent System Operator, Inc., 102 FERC ¶ 61,313 (2003).
D. Proposed Commission Actions To Improve Demand Response and Market Pricing During a Power Shortage
57
has integrated its emergency demand response programs into the market-clearing process, 54 and Midwest ISO is discussing a similar integration based on its 2006 experience.
54 The Commission approved this change in 2003. New York Independent System Operator, Inc., 102 FERC ¶ 61,313 (2003).
D. Proposed Commission Actions To Improve Demand Response and Market Pricing During a Power Shortage
57. The Commission's preliminary view is that the following proposals, if adopted, would address market rules to ensure that demand response can participate directly and would be treated on a comparable basis to supply resources in the organized electric energy and ancillary services markets. This would benefit customers by allowing market prices to reflect the need for demand response (or more generation) during a power shortage. The Commission seeks comment on these proposals. In addition, the Commission does not intend the following proposals to be the only mechanisms open to consideration for ensuring that demand resources be treated comparably to supply resources. Commenters may propose other mechanisms for the organized markets to adopt that would ensure that demand resources and supply resources are treated on a comparable basis in the energy and ancillary services markets.
58. The Commission is considering four proposals to modify the design of wholesale RTO and ISO markets to ensure that demand resources may participate directly in the energy and ancillary services markets on a comparable basis to supply resources. As a complement to these potential reforms, the Commission is also considering revisions to existing mitigation rules to enable the wholesale market prices to help balance supply and demand when power supplies are tight so as to better ensure power system reliability.
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and resources may participate directly in the energy and ancillary services markets on a comparable basis to supply resources. As a complement to these potential reforms, the Commission is also considering revisions to existing mitigation rules to enable the wholesale market prices to help balance supply and demand when power supplies are tight so as to better ensure power system reliability.
59. First, the Commission is considering a proposal to obligate each RTO or ISO to purchase demand resources in its markets for certain ancillary services, similar to any other resources, if the resources meet the necessary technical requirements and the resources submit a bid under the generally-applicable bidding rules at or below the market-clearing price, unless the seller is not permitted to do so by state retail laws or regulations. The Commission proposes modifications to RTO and ISO tariffs that would apply this requirement for energy imbalance, spinning reserves, and supplemental reserves, as defined in the pro forma OATT, or their functional equivalents in an RTO or ISO tariff. 55 To be eligible to supply these ancillary services, demand resources must be capable of reducing demand within seconds or minutes. Demand resources must meet the RTO's or ISO's reasonable size, telemetry, metering, and bidding requirements. For example, the Commission approved a one-megawatt minimum bid by demand resources to provide certain operating reserves in PJM. The RTO or ISO may propose reasonable standards for metering and telemetry needed by system operators to call on these reserves and measure their compliance. Bidding rules for demand resources should not differ from the rules for generation resources unless the reason for the difference is adequately explained and justified. An RTO or ISO may propose other requirements for demand resources to provide these ancillary services that are necessary for reliability and effectiveness.
55 Order No
ators to call on these reserves and measure their compliance. Bidding rules for demand resources should not differ from the rules for generation resources unless the reason for the difference is adequately explained and justified. An RTO or ISO may propose other requirements for demand resources to provide these ancillary services that are necessary for reliability and effectiveness.
55 Order No. 890 also allows qualified demand resources to provide the other ancillary services of reactive supply and voltage control, regulation and frequency response and generator imbalance.
60. The Commission also proposes to modify RTO and ISO tariffs to provide that demand resources must be allowed to provide spinning and supplemental reserves without also being required to sell into the energy market. This change to market rules is intended to address the disincentive for demand response to be an operating reserve. Without this modification, customers may hesitate to offer demand reductions as operating 56
56 See, e.g., PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 (2006) (approving the use of demand resources as operating reserves in PJM). PJM allows demand resources to submit separate bids in its various energy and operating reserve markets.
61. The Commission requests comment on the feasibility and effectiveness of the proposal to require RTOs and ISOs to allow demand resources to provide these ancillary services. It also requests comment on whether to allow each RTO and ISO to propose its own minimum requirements (for example, as to minimum size bids, measurement and telemetry) or to specify appropriate minimum requirements in a Commission rule. In particular, the Commission requests comment on what size a minimum bid should be. Any proposal must comply with the ERO mandatory reliability standards. 57
57 In particular, any proposal must comply with BAL-002 (Disturbance Control Performance) and EOP-002 (Capacity and Energy Emergencies).
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, measurement and telemetry) or to specify appropriate minimum requirements in a Commission rule. In particular, the Commission requests comment on what size a minimum bid should be. Any proposal must comply with the ERO mandatory reliability standards. 57
57 In particular, any proposal must comply with BAL-002 (Disturbance Control Performance) and EOP-002 (Capacity and Energy Emergencies).
62. Second, the Commission is considering a proposal to modify RTO and ISO tariffs to eliminate, during a system emergency, a charge to a buyer in the energy market for taking less electric energy in the real-time market than purchased in the day-ahead market. This proposal is intended to eliminate a disincentive for demand response in the real-time market. We refer to the charge that we propose to eliminate during an emergency as a “deviation charge,” which covers certain uplift costs, as explained below.
63. Before setting out the specific proposal to eliminate this deviation charge, it is necessary to summarize first how the day-ahead and real-time markets relate. A buyer that makes a purchase in the day-ahead market has a commitment to pay for the amount of energy it purchases at the day-ahead market price. If that buyer consumes more energy in real-time than it bought the day before, it pays the day-ahead market price for the amount purchased in the day-ahead market and in addition pays the real-time market price for the extra energy consumed. The real-time price may be higher or lower than the day-ahead price. If the buyer takes less energy in the real-time market than it purchased in the day-ahead market, in effect it sells the reduction back to the market at the real-time market price. The buyer profits if it sells the energy reduction back when the real-time price is higher than the day-ahead price, and suffers a loss when the real-time price is lower. 58 Nothing in the proposal here would change this effect
uyer takes less energy in the real-time market than it purchased in the day-ahead market, in effect it sells the reduction back to the market at the real-time market price. The buyer profits if it sells the energy reduction back when the real-time price is higher than the day-ahead price, and suffers a loss when the real-time price is lower. 58 Nothing in the proposal here would change this effect. If many buyers were to systematically purchase more energy in the day-ahead market than they expect to take in real time, the reduced real-time demand is likely to result in a lower real-time price. The potential loss to the buyers should effectively discourage purchasing more energy than needed in the day-ahead market.
58 This true-up process substitutes for an energy imbalance charge in most RTO and ISO spot markets.
64. Aside from the buyer's market profit or loss, some RTOs and ISOs assess buyers a charge when real-time consumption deviates from day-ahead purchases. This charge recovers at least some types of “uplift” costs, which are the portion of the generators' costs (such as start-up costs) that exceed their energy market revenues. These uplift costs may include the cost of the extra operating reserves needed when the total real-time demand of all buyers exceeds the total scheduled day-ahead demand. The extra reserves are not needed, however, when real-time demand is less than the day-ahead demand. Nevertheless, the deviation charge may apply to any deviation from the day-ahead schedule. 59
59 Although covering operating reserve costs, the deviation charge may also cover other costs not affected by the direction of the deviation.
65. Notwithstanding that these charges are typically meant to serve as an incentive for accurate scheduling, they tend to discourage demand response. When supplies are tight and the real-time price is high, a buyer that reduced load but nevertheless has to pay a deviation charge may be penalized for taking the appropriate action
o cover other costs not affected by the direction of the deviation.
65. Notwithstanding that these charges are typically meant to serve as an incentive for accurate scheduling, they tend to discourage demand response. When supplies are tight and the real-time price is high, a buyer that reduced load but nevertheless has to pay a deviation charge may be penalized for taking the appropriate action. This unintended disincentive may lead a buyer to maintain a high load or discourage an LSE from calling on the demand response capabilities of its retail customers. This negative incentive is especially troublesome during a system emergency when load reduction is needed most.
66. The Commission requests comment on a proposal to require RTOs and ISOs to eliminate this deviation charge for a load reduction during a system emergency. The Commission has already approved a PJM proposal to apply no deviation charge for a load reduction from day-ahead to real-time during a system emergency. 60
60 During an emergency situation a deviation is only assessed if “that deviation increases [the load's] spot market purchases * * *” PJM, Manual 28: Operating Agreement Accounting, at 65 (March 7, 2007), http://www.pjm.com/contributions/pjm-manuals/pdf/m28.pdf.
67. The Commission also requests comment on whether an RTO or ISO should assess a deviation charge for a day-ahead to real-time load reduction when there is no system emergency. Eliminating the charge would encourage demand response, but might have unintended consequences. The Commission understands that these deviation charges cover real costs
/www.pjm.com/contributions/pjm-manuals/pdf/m28.pdf.
67. The Commission also requests comment on whether an RTO or ISO should assess a deviation charge for a day-ahead to real-time load reduction when there is no system emergency. Eliminating the charge would encourage demand response, but might have unintended consequences. The Commission understands that these deviation charges cover real costs. Would eliminating the deviation charge for taking less energy in real-time result in an unfair reallocation of these costs to others? Would the incentive described above—for a buyer to avoid purchasing more than it needs in the day-ahead market—adequately discourage poor scheduling practices, or is it important to retain the deviation charge for this reason? Would eliminating the deviation charge for a real-time load reduction introduce any new opportunity for gaming behavior?
68. As background for the third proposal, demand resources currently participate in every organized real-time market, with the exception of SPP, which is considering such a proposal. Demand resources also currently participate in the organized day-ahead markets of NYISO, ISO-NE, and PJM, while CAISO and the Midwest ISO are considering such a proposal. In addition to participation by individual customers, ARCs aggregate demand reductions by retail customers and bid these aggregated reductions into the energy markets. The FERC Staff Demand Response Assessment and comments during our technical conferences indicate that more needs to be done to facilitate direct participation in the energy markets by ARCs who bid into the wholesale markets aggregated demand reductions on behalf of retail customers and other customers. The potential contribution from ARCs has increased with technological developments that make demand response more automated.
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sessment and comments during our technical conferences indicate that more needs to be done to facilitate direct participation in the energy markets by ARCs who bid into the wholesale markets aggregated demand reductions on behalf of retail customers and other customers. The potential contribution from ARCs has increased with technological developments that make demand response more automated.
69. The Commission is considering a proposal to require RTOs and ISOs to amend their market rules as necessary to permit an ARC to bid a demand reduction on behalf of retail customers directly into the RTO's or ISO's organized markets. This proposal is intended to remove a barrier to demand response in some RTO and ISO energy markets 61 by allowing an ARC to act as an intermediary for many small retail loads that cannot individually participate in the organized market
61 Aggregation of retail customers is used now in the energy markets of PJM, ISO-NE, and NYISO and in PJM's Synchronized Reserve and Regulation Service market in PJM. PJM's aggregation of retail customers is integrated into its market rules for PJM's Interchange Energy Market. Aggregation of retail customers in ISO-NE and NYISO are separate programs that are not yet part of the market rules.
70. Under this proposal, the market rules may not exclude a demand response bid from a third-party ARC that is not a LSE unless state retail electric laws or regulations do not permit this. This proposal would apply to each of the RTO's or ISO's organized markets into which an LSE may submit a demand response bid. The market rules for ARCs may not differ from the rules for LSEs, except as needed to comply with state retail service laws and regulation, unless the RTO or ISO satisfactorily explains the reason for any such difference in its compliance filing. RTOs and ISOs may, however, set rules for ARC participation that are the same as or equivalent to its rules for LSEs
SE may submit a demand response bid. The market rules for ARCs may not differ from the rules for LSEs, except as needed to comply with state retail service laws and regulation, unless the RTO or ISO satisfactorily explains the reason for any such difference in its compliance filing. RTOs and ISOs may, however, set rules for ARC participation that are the same as or equivalent to its rules for LSEs. Such rules may address such subjects as bidding requirements; technical requirements for communicating demand response bids and measuring demand response performance; a minimum organized market price above which the ARC may offer to reduce load and below which it may not; a minimum or maximum number of contiguous hours for which the load reduction must be committed; and how to account for start-up costs associated with reducing load, creditworthiness, and settlement procedures.
71. Under this proposal, the Commission also would direct the RTOs and ISOs to coordinate to identify common issues, best practices solutions, and market rules that are consistent between regions, particularly in the areas of market procedures, bidding protocols, communication protocols, and measurement and verification. The Commission would direct the RTOs and ISOs to report, within 90 days of the effective date of any Final Rule in this proceeding, on how they intend to explore best practices, common issues, and market rules for the direct participation of demand resources in their markets. 62 Although we would direct RTOs and ISOs to consider best practices, the Commission does not intend that every region would have to adopt the same practices, rules, or procedures.
62 The Commission would also encourage the RTOs and ISOs to work within the ISO/RTO Council to consider best practices that may be applicable to the members' regions. The Commission also encourages continued participation in the North American Energy Standards Board's (NAESB) measurement and verification initiative.
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every region would have to adopt the same practices, rules, or procedures.
62 The Commission would also encourage the RTOs and ISOs to work within the ISO/RTO Council to consider best practices that may be applicable to the members' regions. The Commission also encourages continued participation in the North American Energy Standards Board's (NAESB) measurement and verification initiative.
72. The Commission requests comments on the proposal to require RTOs and ISOs to amend their market rules to permit demand response of aggregated retail customers. Are there other requirements the Commission should consider to improve the efficiency of aggregation of retail customers? The Commission also requests comments on the conditions under which a RTO or ISO aggregation of retail customers program would no longer be needed.
73. The Commission also requests comment on whether aggregation of retail customers allows inappropriate compensation when a retail customer is paid for wholesale demand reduction and also saves in its retail bill from the same demand reduction. The Edison Electric Institute (EEI) has argued that the payments to customers represent subsidies that are not justified or a form of double payment. 63 For example, because a customer's bill decreases for every megawatt-hour (MWh) not consumed, if that customer is also paid an amount by the RTO or ISO for the same MWh not consumed, EEI and others allege that the customer has been compensated twice. They contend that use of time-based rates is the correct way to achieve price-responsive demand and that any additional payment to retail customers by RTOs and ISOs is inappropriate and should be considered a temporary measure at best. Others disagree with this criticism, arguing that the price reduction does not fully reflect the social benefits produced by the demand reduction
compensated twice. They contend that use of time-based rates is the correct way to achieve price-responsive demand and that any additional payment to retail customers by RTOs and ISOs is inappropriate and should be considered a temporary measure at best. Others disagree with this criticism, arguing that the price reduction does not fully reflect the social benefits produced by the demand reduction. 64 Further, critics of aggregation of retail customers programs charge that the incentives for aggregation of retail customers programs in energy markets are inconsistent across RTOs and ISOs and the programs are susceptible to gaming behavior. 65
63 See Technical Conference on Demand Response and Advanced Metering on January 25, 2006, Tr. 26 (Richard Tempchin, EEI) (Docket No. AD06-2-000), http://elibrary.ferc.gov:0/idmws/file_list.asp?document_id=4378387.
64 R.N. Boisvert and B.F. Neenan, Neenan Associates, Social Welfare Implications of Demand Response Programs in Competitive Electricity Markets (August 2003), http://eetd.lbl.gov/ea/EMP/reports/LBNL-52530.pdf.
65 The potential for gaming occurs if an aggregator submits a demand reduction bid on behalf of customers that will have reduced consumption anyway for another reason such as maintenance, vacation, or holiday. The Commission approved NYISO's bid floor of $75/MWh in its Day Ahead Demand Response Program to eliminate or reduce the incentive for this behavior. New York Independent System Operator, Inc., 109 FERC ¶ 61,101 (2004).
74. The Commission requests comments on how to appropriately compensate a customer for demand response. We seek comment on whether there is any inappropriate double compensation. We also solicit comments on whether providing an additional payment is appropriate to compensate for the value of the demand response. For example, PJM pays the market-clearing price less the generation and transmission component of each retail customer's retail rate (this price reduction is sometimes called the generation offset)
comment on whether there is any inappropriate double compensation. We also solicit comments on whether providing an additional payment is appropriate to compensate for the value of the demand response. For example, PJM pays the market-clearing price less the generation and transmission component of each retail customer's retail rate (this price reduction is sometimes called the generation offset). 66 Would a PJM-type generation offset reduce the amount of the alleged double compensation? 67 Would a generation offset encourage demand response more so during a period of high price, when it is needed most?
66 For example, if the market-clearing price is $100 per MWh and the generation component of a customer's retail rate is $75 per MWh, the payment for the load curtailment would be $25 per MWh ($100-$75). In PJM's Economic Load Response Program, this netting is applied when the market-clearing price is below $75/MWh. See section 3.3A.4(d) of the PJM Operating Agreement.
67 PJM Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002).
75. Fourth, the Commission is considering whether to modify RTO and ISO market power mitigation rules and other market rules when demand is nearing the amount of available supply. When supplies are short relative to demand and reliability is threatened, market rules that limit the market price may have the unintended effect of making demand response less attractive to its providers. The Commission seeks comment on four potential ways to modify mitigation rules to allow the market price to better reflect the value of lost load in an emergency situation.
76. One way to address this issue to require that RTOs and ISOs increase the energy bid caps and price caps above the current levels only during an emergency. When the market price is constrained, it is not possible to distinguish customers who place a high value on uninterrupted electric service from other customers who would reduce demand rather than pay a price that reflects that high value
.
76. One way to address this issue to require that RTOs and ISOs increase the energy bid caps and price caps above the current levels only during an emergency. When the market price is constrained, it is not possible to distinguish customers who place a high value on uninterrupted electric service from other customers who would reduce demand rather than pay a price that reflects that high value. An emergency situation typically occurs when a system faces a shortage of operating reserves—a reliability standard violation. Demand for energy in the real-time market then competes with the need for spare generation for operating reserves to maintain grid reliability. To maintain operating reserves, electric energy service must be reduced immediately, either by prorating the load reduction across all customers or by using the market price to allocate the limited energy available to those who value it most. In defined periods of tight supply, PJM's market rules remove sellers' bid caps, but keep the market-wide $1,000 per MWh offer cap. If the market-wide cap was also raised, the
77. The Commission requests comment on this proposal to raise energy bid caps and market-wide caps in an emergency, and on what operating conditions should constitute an emergency shortage.
78. A second way to allow the market price to reduce demand during an emergency is to raise bid caps above the current level only for demand bids 68 —the offers by buyers to purchase a certain amount of energy at a given price—in the day-ahead and real-time markets, while keeping generation bid caps in place. That is, a buyer would be allowed to inform the RTO or ISO about how much energy it would purchase at various prices above the current bid caps. Under this proposal, such high demand bids would not only be allowed but also would be allowed to set the market price if they clear the market. 69 The high market price under this approach would create an incentive for all buyers to lower their demands during an emergency
ould be allowed to inform the RTO or ISO about how much energy it would purchase at various prices above the current bid caps. Under this proposal, such high demand bids would not only be allowed but also would be allowed to set the market price if they clear the market. 69 The high market price under this approach would create an incentive for all buyers to lower their demands during an emergency. To the extent the buyers are not also sellers, this approach raises fewer concerns about market power than the first approach, which raises bid caps for all market participants. The Commission requests comment on whether this method would be more effective, less subject to the exercise of market power, or otherwise easier to implement than raising all bid and price caps.
68 A demand bid is different from a demand reduction bid. The first is an offer by a potential purchaser to buy a certain amount of energy at a given market price, and the second is an offer by a purchaser to reduce his normal purchase by a given amount in return for compensation.
69 For example, a demand bid of $1,500 could set the market price under the following conditions. If there is not enough generation capacity to meet all demand after the RTO or ISO reserves enough generating capacity to meet ancillary service requirements and if there is just enough generating capacity to meet the combination of: (1) All ancillary service requirements, (2) all price-insensitive demand ( i.e. , buyers who are willing to purchase energy at any price), and (3) all demand with price bids above $1,500 per MWh, the market would clear at a price of $1,500 per MWh. In this case, a demand bid of $1,500/MWh would set the market price. Buyers bidding less than this price for all or part of their total demand are in effect choosing not to purchase energy for $1,500 per MWh, and thus would have to reduce their demand accordingly. All other buyers would receive their requested energy.
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above $1,500 per MWh, the market would clear at a price of $1,500 per MWh. In this case, a demand bid of $1,500/MWh would set the market price. Buyers bidding less than this price for all or part of their total demand are in effect choosing not to purchase energy for $1,500 per MWh, and thus would have to reduce their demand accordingly. All other buyers would receive their requested energy.
79. A third way to allow the market price to reduce demand during an emergency is to require a demand curve for operating reserves in each RTO or ISO market. Under this approach, when available generating capacity falls short of combined energy demand and operating reserve requirements, the market price for energy and operating reserves would increase to specified levels (typically above the market-wide seller offer cap) and the price level would increase with the severity of the shortage. This approach would ensure that market prices reflect tight conditions on the grid without altering any of the market power mitigation restrictions on either supply or demand bids. The market rules in NYISO and ISO-NE include a demand curve for operating reserves that sets the real-time market price when operating reserves are low. These rules are intended to help assure reliability by reducing demand significantly during a shortage. The Commission could require each RTO and ISO to establish market rules that set real-time market prices at specific pre-determined values during an emergency when operating reserves are low. The Commission requests comment on whether it should require all ISOs and RTOs to adopt such a demand curve, how to set its parameters, and how to apply these rules to any local shortages with high locational prices that do not have a significant effect throughout the entire RTO or ISO region. In particular, how should an emergency be defined now that mandatory reliability rules are in effect?
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he Commission requests comment on whether it should require all ISOs and RTOs to adopt such a demand curve, how to set its parameters, and how to apply these rules to any local shortages with high locational prices that do not have a significant effect throughout the entire RTO or ISO region. In particular, how should an emergency be defined now that mandatory reliability rules are in effect?
80. A fourth way to allow the market price to reduce demand during an emergency is to set the market-clearing price at the payment made to participants in an emergency demand response program, described above. For example, if payments to participants in emergency demand response programs are set at $500 per MWh, the market-clearing price when these resources are called would be set at $500 per MWh. This approach would avoid the problem caused by the drop in market price that results from calling on an emergency demand response provider, which sends the wrong price signal to both suppliers and consumers. To implement this approach, the Commission would propose to amend RTO and ISO market rules to allow the payment to emergency demand response providers to set the market-clearing price for all supply and demand resources dispatched. RTOs and ISOs would have to amend their market rules on unit commitment and settlement to adjust wholesale energy prices outside the normal clearing process. RTOs and ISOs may also have to review and adjust the emergency conditions under which these emergency demand response resources would be called.
81. The Commission requests comment on these four ways to allow the market price to reduce demand during an emergency
ve to amend their market rules on unit commitment and settlement to adjust wholesale energy prices outside the normal clearing process. RTOs and ISOs may also have to review and adjust the emergency conditions under which these emergency demand response resources would be called.
81. The Commission requests comment on these four ways to allow the market price to reduce demand during an emergency. Should any be used and, if so, which way or combination of ways would be most beneficial? For any of these ways to allow the market price to elicit demand reduction during an emergency, the Commission requests comments on whether it should require a specific method, or, given the differences in market design among the RTOs and ISOs, adopt the general requirement and direct each RTO and ISO to develop its own compliance mechanism.
82. Finally, as discussed above, some RTOs and ISOs have quantified the cost-effectiveness of demand response in their wholesale power markets. The Commission requests comments on whether it should require all RTOs and ISOs to do this for their markets that have demand response.
IV. Long-Term Power Contracting in Organized Markets
83. Competitive wholesale markets need a strong infrastructure—both adequate electricity supply and a robust interstate transmission grid. Long-term contracts are an important tool to achieve and maintain a strong power infrastructure, particularly for new entrants into the generation sector and especially for many renewable energy developers. Long-term contracts are important to effective competition both in regions with organized wholesale markets and in regions without organized markets. Competitive solicitation is a sound vehicle to support long-term contracts in regions with and without organized markets. Order No. 890 and long-term firm transmission rights support long-term transmission service contracts in both kinds of regions
. Long-term contracts are important to effective competition both in regions with organized wholesale markets and in regions without organized markets. Competitive solicitation is a sound vehicle to support long-term contracts in regions with and without organized markets. Order No. 890 and long-term firm transmission rights support long-term transmission service contracts in both kinds of regions. In this proceeding, the Commission proposes additional steps to facilitate opportunities for long-term power contracting in organized markets. Although long-term contracts are important in all regions, the
A. Importance of Long-Term Power Contracts and Factors Affecting Contracting Decisions by Buyers and Sellers
84. The Commission believes that the organized market regions facilitate long-term contracting in several ways, such as eliminating pancaked rates for long distance power sales, eliminating internal loop flow problems that might otherwise lead to unplanned curtailment of long distance transmission service, and ensuring reliable transmission operation over a large area that encompasses many potential sellers and buyers of long-term power. These and other features of RTO and ISO transmission services expand the geographic scope of markets available to sellers and buyers of long-term power. Our goal here is to further improve opportunities for long-term contracting in RTO and ISO regions.
85. It is important that wholesale sellers and buyers have adequate opportunities to sell and buy electric power through long-term power contracts to allow them to manage their exposure to uncertain future spot market prices. Sellers and buyers should also have the opportunity to sell and buy electric power in the spot market. The Commission believes that it is important for buyers and sellers in organized markets to be able to choose a portfolio of short-term, intermediate-term, and long-term power supplies. Having portfolio choice allows market participants to manage the risk that comes from uncertainty
arket prices. Sellers and buyers should also have the opportunity to sell and buy electric power in the spot market. The Commission believes that it is important for buyers and sellers in organized markets to be able to choose a portfolio of short-term, intermediate-term, and long-term power supplies. Having portfolio choice allows market participants to manage the risk that comes from uncertainty. Forward power contracting by buyers combined with purchases from a spot market with demand response can be an efficient and low-cost way of meeting customer needs because both buyers and sellers can hedge risk as well as adapt to actual real-time supply and demand conditions. Competitive forward power contracting allows many sellers to compete to provide electric service, and greater reliance on long-term power contracting could decrease the incentive for sellers to exercise market power in the spot market if there is reduced opportunity to profit from such action.
86. At the Commission's technical conference on May 8, 2007, speakers on the long-term power contracting panel agreed that long-term power contracts are important to a well functioning electric market. 70 Customers argued that long-term contracts are essential to providing price stability and supporting the adequacy of supply over the long run. 71 Sellers argued that long-term contracts are important and often essential to financing new generation sources.
70 Transcript of Conference at 111, Conference on Competition in Wholesale Power Markets, Docket No. AD07-7-000 (May 8, 2007).
71 Id. at 107.
87. Customers and sellers differed sharply, however, on the nature and extent of any impediments to long-term contracts. Customers argued that suppliers are reluctant to sell power under long-term contracts at a price attractive to those customers. 72 They argued that the presence of liquid spot markets gives suppliers an incentive to sell most of their output on a daily or hourly basis, not through long-term contracts
ers differed sharply, however, on the nature and extent of any impediments to long-term contracts. Customers argued that suppliers are reluctant to sell power under long-term contracts at a price attractive to those customers. 72 They argued that the presence of liquid spot markets gives suppliers an incentive to sell most of their output on a daily or hourly basis, not through long-term contracts. By contrast, suppliers and their representatives said they are willing to sign long-term power contracts but asserted that buyers simply do not want to pay the long-term cost of power. In particular, they alleged that customers do not want to pay enough to finance new generation and any needed transmission investment. With respect to existing assets, suppliers argued that customers often want a price pegged to a particular fuel ( e.g. , coal or nuclear), even if that price does not reflect the long-term market value of electric power.
72 See, e.g. , Post-Technical Conference Comments of the American Public Power Association, Docket No. AD07-7-000 (Mar. 13, 2007); Supplemental Comments of the Electricity Consumers Resource Council, Docket No. AD07-7-000 (Mar. 12, 2007).
B. Commission Actions To Support Long-Term Power Contracts
88. The Commission fully supports reliance on long-term contracts to provide price stability, hedge risk, and support financing for new investments. In this regard, the Commission has taken a number of steps to facilitate long-term contracting. The Commission adopted a final rule on long-term transmission rights for organized market regions in Order No. 681. 73 The assurance of long-term transmission availability at a predictable cost is an important component of a buyer's decision to sign a long-term power contract with a distant supplier.
73 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, 71 FR 43,564 (August 1, 2006), FERC Stats. & Regs. ¶ 31,226, order on reh'g, Order No. 681-A, 117 FERC ¶ 61,201 (2006).
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73 The assurance of long-term transmission availability at a predictable cost is an important component of a buyer's decision to sign a long-term power contract with a distant supplier.
73 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, 71 FR 43,564 (August 1, 2006), FERC Stats. & Regs. ¶ 31,226, order on reh'g, Order No. 681-A, 117 FERC ¶ 61,201 (2006).
89. Also, the Commission adopted transmission planning reforms in Order No. 890. These reforms provide an open and transparent process for wholesale entities and transmission providers to plan for the long-term needs of their customers, including making transmission investments that can support long-term contracts for generation.
90. The Commission has also sought to lower barriers to entry for new generation that can support long-term contracts. In a series of orders (Order Nos. 2003, 2006, and 661), 74 the Commission adopted interconnection rules for large, small, and wind generators that provide a known and stable process for requesting interconnection, receiving timely responses from transmission service providers, and determining who pays for various costs associated with the interconnection process and facilities. The Commission also reformed capacity e.g. , three years) to be more consistent with the time necessary to construct new generation. 75
74 Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,146 (2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC , 475 F.3d 1277 (D.C. Cir. 2007); Standardization of Small Generator Interconnection Agreements and Procedures, Order No. 2006, FERC Stats
reh'g, Order No. 2003-B, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC , 475 F.3d 1277 (D.C. Cir. 2007); Standardization of Small Generator Interconnection Agreements and Procedures, Order No. 2006, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,180, order on reh'g, Order No. 2006-A, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,196 (2005), order granting clarification, Order No. 2006-B, FERC Stats. & Regs. ¶ 31,221 (2006), appeal pending sub nom. Consolidated Edison Co. of New York, Inc., et al. v. FERC (U.S.C.A., D.C. Circuit, Docket Nos. 06-1018, et al. ); Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,186, order on reh'g, Order No. 661-A, FERC Stats. & Regs., Regulations Preambles 2001-2005 ¶ 31,198 (2005).
75 See Devon Power L.L.C., 115 FERC ¶ 61,340, order on reh'g, 117 FERC ¶ 61,133 (2006); PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006).
91. Through this ANOPR the Commission intends to consider whether there are other concrete steps that can be taken to facilitate long-term contracting.
C. Proposed Commission Actions To Facilitate Long-Term Power Contracting
92. The Commission seeks comments on any concrete steps it can take to facilitate voluntary long-term power contracting in organized market regions. In seeking comment on this issue, however, the Commission is mindful of the limits of its jurisdiction. The Commission cannot compel buyers and sellers to enter into long-term contracts, and the purchasing practices of LSEs are often dictated by state policies, not those of this Commission.
93
rete steps it can take to facilitate voluntary long-term power contracting in organized market regions. In seeking comment on this issue, however, the Commission is mindful of the limits of its jurisdiction. The Commission cannot compel buyers and sellers to enter into long-term contracts, and the purchasing practices of LSEs are often dictated by state policies, not those of this Commission.
93. Based on the comments received in the technical conferences and other actions being considered in various markets, the Commission seeks comment on whether it should:
• Provide greater market transparency by requiring RTOs and ISOs to post information that could facilitate long-term contracts, such as by aggregating and posting information on long-term contract prices and quantities on a periodic basis. Would this information prove helpful to buyers and sellers? If so, how could the information be reported in a way that protects the confidentiality of individual contracts? Would other information be helpful to long-term contracting, such as the posting of estimates of transmission constraints and congestion costs on a long-term basis?
• Require or encourage efforts to develop new standardized forward products. Would standardized products better facilitate long-term contracting? If so, what role should the Commission play? Should it encourage RTOs or ISOs to play an active role in this area or would that place them in a position of undertaking commercial functions? Is this a role better played by NAESB or other industry groups?
• Take other steps such as having a dedicated portion of the ISO or RTO Web site for market participants to post offers to buy or sell power long-term? Would this prove helpful or is it a service that is better provided by the market?
94
role in this area or would that place them in a position of undertaking commercial functions? Is this a role better played by NAESB or other industry groups?
• Take other steps such as having a dedicated portion of the ISO or RTO Web site for market participants to post offers to buy or sell power long-term? Would this prove helpful or is it a service that is better provided by the market?
94. Further, the Commission requests comments on whether we should consider any modification of the data requirements of the Electric Quarterly Report (EQR)—for example, to report the start date, term, and end date of long term power contracts—to provide information that would make transparent the average prices of long term power contracts of various terms and vintages.
V. Market Monitoring Policies
95. Market monitors have played an integral role in the organized electric markets since the latter's inception, providing valuable reporting and analysis services not only to the Commission, but also to the RTOs and ISOs, to market participants, and to state commissions. In light of their imp

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Source: Frix Law Library, https://www.frixlaw.com/law-library/statutes/FR_PRORULE_E7-12550. Check the current official text before relying on it. Not legal advice.