thefederalregister.com

Daily Rules, Proposed Rules, and Notices of the Federal Government

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-17-000; Order No. 745]

Demand Response Compensation in Organized Wholesale Energy Markets

AGENCY: Federal Energy Regulatory Commission, Energy.
ACTION: Final rule.
SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission (Commission) amends its regulations under the Federal Power Act to ensure that when a demand response resource participating in an organized wholesale energy market administered by a Regional Transmission Organization (RTO) or Independent System Operator (ISO) has the capability to balance supply and demand as an alternative to a generation resource and when dispatch of that demand response resource is cost-effective as determined by the net benefits test described in this rule, that demand response resource must be compensated for the service it provides to the energy market at the market price for energy, referred to as the locational marginal price (LMP). This approach for compensating demand response resources helps to ensure the competitiveness of organized wholesale energy markets and remove barriers to the participation of demand response resources, thus ensuring just and reasonable wholesale rates.
DATES: Effective Date:This Final Rule will become effective on April 25, 2011. Dates for compliance and other required filings are provided in the Final Rule.
FOR FURTHER INFORMATION CONTACT:

David Hunger (Technical Information),Office of Energy Policy and Innovation,Federal Energy Regulatory Commission,888 First Street, NE., Washington, DC 20426,(202) 502-8148,david.hunger@ferc.gov; Dennis Hough (Legal Information),Office of the General Counsel,Federal Energy Regulatory Commission,888 First Street, NE., Washington, DC 20426,(202) 502-8631,dennis.hough@ferc.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents (Issued March 15, 2011) Paragraph Nos. I. Introduction 1 II. Background 8 III. Procedural History 15 IV. Discussion 17 A. Compensation Level 18 1. NOPR Proposal 18 2. Comments 20 (a) Capability of Demand Response and Generation Resources to Balance Energy Markets 20 (b) Appropriateness of a Net Benefits Test 38 (c) Standardization or Regional Variations in Compensation 43 3. Commission Determination 45 B. Implementation of a Net Benefits Test 68 1. Comments 68 2. Commission Determination 78 C. Measurement and Verification 86 1. NOPR Proposal 86 2. Comments 88 3. Commission Determination 93 D. Cost Allocation 96 1. NOPR Proposal 96 2. Comments 97 3. Commission Determination 99 E. Commission Jurisdiction 103 1. Comments 103 2. Commission Determination 112 V. Information Collection Statement 116 VI. Environmental Analysis 121 VII. Regulatory Flexibility Act 122 VIII. Document Availability 130 IX. Effective Date and Congressional Notification 133 Regulatory Text Appendix 1—List of Commenters Appendix 2—Dissenting Statement

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

I. Introduction

1. This Final Rule addresses compensation for demand response in Regional Transmission Organization (RTO) and Independent System Operator (ISO) organized wholesale energy markets,i.e.,the day-ahead and real-time energy markets. As the Commission has previously recognized, a market functions effectively only when both supply and demand can meaningfully participate. The Commission, in the Notice of Proposed Rulemaking (NOPR) issued in this proceeding on March 18, 2010, proposed a remedy to concerns that current compensation levels inhibited meaningful demand-side participation.1 After nearly 3,800 pages of comments, a subsequent technical conference, and the opportunity for additional comment, we now take final action.

1 Demand Response Compensation in Organized Wholesale Energy Markets,Notice of Proposed Rulemaking, 75 FR 15362 (Mar. 29, 2010), FERC Stats. & Regs. ¶ 32,656 (2010) (NOPR).

2. We conclude that when a demand response2 resource3 participating in an organized wholesale energy market4 administered by an RTO or ISO has the capability to balance supply and demand as an alternative to a generation resource and when dispatch of that demand response resource is cost-effective as determined by the net benefits test described herein, that demand response resource must be compensated for the service it provides to the energy market at the market price for energy, referred to as the locational marginal price (LMP).5 The Commission finds that this approach to compensation for demand response resources is necessary to ensure that rates are just and reasonable in the organized wholesale energy markets. Consistent with this finding, this Final Rule adds section 35.28(g)(1)(v) to the Commission's regulations to establish a specific compensation approach for demand response resources participating in the organized wholesale energy markets administered by RTOs and ISOs. The Commission is not requiring the use of this compensation approach when demand response resources do not satisfy the capability and cost-effectiveness conditions noted above.6

2Demand response means a reduction in the consumption of electric energy by customers from their expected consumption in response to an increase in the price of electric energy or to incentive payments designed to induce lower consumption of electric energy. 18 CFR 35.28(b)(4) (2010).

3Demand response resource means a resource capable of providing demand response. 18 CFR 35.28(b)(5).

4The requirements of this final rule apply only to a demand response resource participating in a day-ahead or real-time energy market administered by an RTO or ISO. Thus, this Final Rule does not apply to compensation for demand response under programs that RTOs and ISOs administer for reliability or emergency conditions, such as, for instance, Midwest ISO's Emergency Demand Response, NYISO's Emergency Demand Response Program, and PJM's Emergency Load Response Program. This Final Rule also does not apply to compensation in ancillary services markets, which the Commission has addressed elsewhere.See, e.g., Wholesale Competition in Regions with Organized Electric Markets,Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008) (Order No. 719).

5LMP refers to the price calculated by the ISO or RTO at particular locations or electrical nodes or zones within the ISO or RTO footprint and is used as the market price to compensate generators. There are variations in the way that RTOs and ISOs calculate LMP; however, each method establishes the marginal value of resources in that market. Nothing in this Final Rule is intended to change RTO and ISO methods for calculating LMP.

6The Commission's findings in this Final Rule do not preclude the Commission from determining that other approaches to compensation would be acceptable when these conditions are not met.

3. This cost-effectiveness condition, as determined by the net benefits test described herein, recognizes that, depending on the change in LMP relative to the size of the energy market, dispatching demand response resources may result in an increased cost per unit ($/MWh) to the remaining wholesale load associated with the decreased amount of load paying the bill. This is the case because customers are billed for energy based on the units, MWh, of electricity consumed. We refer to this potential result as the billing unit effect of dispatching demand response. By contrast, dispatching generation resources does not produce this billing unit effect because it does not result in a decrease of load. To address this billing unit effect, the Commission in this Final Rule requires the use of the net benefits test described herein to ensure that the overall benefit of the reduced LMP that results from dispatching demand response resources exceeds the cost of dispatching and paying LMP to those resources. When the net benefits test described herein is satisfied and the demand response resource clears in the RTO's or ISO's economic dispatch, the demand response resource is a cost-effective alternative to generation resources for balancing supply and demand.

4. To implement the net benefits test described herein, we direct each RTO and ISO to develop a mechanism as an approximation to determine a price level at which the dispatch of demand response resources will be cost-effective. The RTO or ISO should determine, based on historical data as a starting point and updated for changes in relevant supply conditions such as changes in fuel prices and generator unit availability, the monthly threshold price corresponding to the point along the supply stack beyond which the overall benefit from the reduced LMP resulting from dispatching demand response resources exceeds the cost of dispatching and paying LMP to those resources. This price level is to be updated monthly, by each ISO or RTO, as the historic data and relevant supply conditions change.7

7In its compliance filing an RTO or ISO may attempt to show, in whole or in part, how its proposed or existing practices are consistent with or superior to the requirements of this Final Rule.

5. This Final Rule also sets forth a method for allocating the costs of demand response payments among all customers who benefit from the lower LMP resulting from the demand response.

6. The tariff changes needed to implement the compensation approach required in this Final Rule, including the net benefits test, measurement and verification explanation and proposed changes, and the cost allocation mechanism must be made on or before July 22, 2011. All tariff changes directed herein should be submitted as compliance filings pursuant to this Final Rule, not pursuant to section 205 of the Federal Power Act (FPA).8 Accordingly, each RTO's or ISO's compliance filing to this Final Rule will become effective prospectively from the date of the Commission order addressing that filing, and not within 60 days of submission.

816 U.S.C. 824d (2006).

7. In addition, we believe that integrating a determination of the cost-effectiveness of demand response resources into the dispatch of the ISOs and RTOs may be more precise than the monthly price threshold and, therefore, provide the greatest opportunity for load to benefit from participation of demand response in the organized wholesale energy market administered by an RTO or ISO. However, we acknowledge the position of several of the RTOs and ISOs that modification of their dispatch algorithms to incorporate the costs related to demand response may be difficult in the near term. In light of those concerns, we require each RTO and ISO to undertake a study examining the requirements for and impacts of implementing a dynamic approach which incorporates the billing unit effect in the dispatch algorithm to determine when paying demand response resources the LMP results in net benefits to customers in both the day-ahead and real-time energy markets. The Commission directs each RTO and ISO to file the results of this study with the Commission on or before September 21, 2012.9

9We note that this report is for informational purposes only and will neither be noticed nor require Commission action.

II. Background

8. Effective wholesale competition protects customers by, among other things, providing more supply options, encouraging new entry and innovation, and spurring deployment of new technologies.10 Improving the competitiveness of organized wholesale energy markets is therefore integral to the Commission fulfilling its statutory mandate under the FPA to ensuresupplies of electric energy at just, reasonable, and not unduly discriminatory or preferential rates.11

10 See, e.g., Wholesale Competition in Regions with Organized Electric Markets,Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281, at P 1 (2008) (Order No. 719);see also Regional Transmission Organizations,Order No. 2000, FERC Stats. & Regs. ¶ 31,089, at P 1 (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, Washingtonv.FERC,272 F.3d 607, 348 U.S. App. DC 205 (DC Cir. 2001).

1116 U.S.C. 824d (2006); Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 1.

9. As the Commission recognized in Order No. 719, active participation by customers in the form of demand response in organized wholesale energy markets helps to increase competition in those markets.12 Demand response, whereby customers reduce electricity consumption from normal usage levels in response to price signals, can generally occur in two ways: (1) Customers reduce demand by responding to retail rates that are based on wholesale prices (sometimes called “price-responsive demand”); and (2) customers provide demand response that acts as a resource in organized wholesale energy markets to balance supply and demand. While a number of States and utilities are pursuing retail-level price-responsive demand initiatives based on dynamic and time-differentiated retail prices and utility investments in demand response enabling technologies, these are State efforts, and, thus, are not the subject of this proceeding. Our focus here is on customers or aggregators of retail customers providing, through bids or self-schedules, demand response that acts as a resource in organized wholesale energy markets.

12 SeeOrder No. 719, FERC Stats. & Regs. ¶ 31,281 at P 48.

10. As the Commission stated in Order No. 719,13 and emphasized in the NOPR,14 there are several ways in which demand response in organized wholesale energy markets can help improve the functioning and competitiveness of those markets. First, when bid directly into the wholesale market, demand response can facilitate RTOs and ISOs in balancing supply and demand, and thereby, help produce just and reasonable energy prices.15 This is because customers who choose to respond will signal to the RTO or ISO and energy market their willingness to reduce demand on the grid which may result in reduced dispatch of higher-priced resources to satisfy load.16 Second, demand response can mitigate generator market power.17 This is because the more demand response that sees and responds to higher market prices, the greater the competition, and the more downward pressure it places on generator bidding strategies by increasing the risk to a supplier that it will not be dispatched if it bids a price that is too high.18 Third, demand response has the potential to support system reliability and address resource adequacy19 and resource management challenges surrounding the unexpected loss of generation. This is because demand response resources can provide quick balancing of the electricity grid.20

13 Wholesale Competition in Regions with Organized Electric Markets,Order No. 719-A, FERC Stats. & Regs. ¶ 31,292, at P 48 (2009).

14NOPR, FERC Stats. & Regs. ¶ 32,656 at P 4.

15For example, a study conducted by PJM, which simulated the effect of demand response on prices, demonstrated that a modest three percent load reduction in the 100 highest peak hours corresponds to a price decline of six to 12 percent. ISO-RTO Council Report, Harnessing the Power of Demand How RTOs and ISOs Are Integrating Demand Response into Wholesale Electricity Markets, found athttp://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/IRC_DR_Report_101607.pdf.

16 Id.(“Demand response tends to flatten an area's load profile, which in turn may reduce the need to construct and use more costly resources during periods of high demand; the overall effect is to lower the average cost of producing energy.”).

17 SeeComments of NYISO's Independent Market Monitor filed in Docket No. ER09-1142-000, May 15, 2009 (Demand response “contributes to reliability in the short-term, resource adequacy in the long-term, reduces price volatility and other market costs, and mitigates supplier market power.”).

18 Id.

19 SeeISO-RTO Council Report, Harnessing the Power of Demand How RTOs and ISOs Are Integrating Demand Response into Wholesale Electricity Markets at 4, found athttp://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/IRC_DR_Report_101607.pdf(“Demand response contributes to maintaining system reliability. Lower electric load when supply is especially tight reduces the likelihood of load shedding. Improvements in reliability mean that many circumstances that otherwise result in forced outages and rolling blackouts are averted, resulting in substantial financial savings * * *.”).

20For instance, in ERCOT, on February 26, 2008, through a combination of a sudden loss of thermal generation, drop in power supplied by wind generators, and a quicker-than-expected ramping up of demand, ERCOT found itself short of reserves. The system operator called on all demand response resources, and 1200 MW of Load acting as Resource (LaaRs) responded quickly, bringing ERCOT back into balance. Oak Ridge Nat'l Lab., Nat'l Renewable Energy Lab., Tech. Rep. NREL/TP-500-43373, ERCOT Event on Feb. 26, 2008: Lessons Learned (Jul. 2008).

11. Congress has recognized the importance of demand response by enacting national policy requiring its facilitation.21 Consistent with that policy, the Commission has undertaken several reforms to support competitive wholesale energy markets by removing barriers to participation of demand response resources. For example, in Order No. 890, the Commission modified thepro formaOpen Access Transmission Tariff to allow non-generation resources, including demand response resources, to be used in the provision of certain ancillary services where appropriate on a comparable basis to service provided by generation resources.22 Order No. 890-A further required transmission providers to develop transmission planning processes that treat all resources, including demand response, on a comparable basis.23

21 SeeEnergy Policy Act of 2005, Public Law 109-58, § 1252(f), 119 Stat. 594, 965 (2005) (“It is the policy of the United States that * * * unnecessary barriers to demand response participation in energy, capacity, and ancillary service markets shall be eliminated.”).

22 Preventing Undue Discrimination and Preference in Transmission Service,Order No. 890, FERC Stats. & Regs. ¶ 31,241, at P 887-88 (2007),order on reh'g,Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007),order on reh'g and clarification,Order No. 890-B, 123 FERC ¶ 61,299 (2008),order on reh'g,Order No. 890-C, 126 FERC ¶ 61,228 (2009),order on clarification,Order No. 890-D, 129 FERC ¶ 61,126 (2009).

23Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 216.

12. In Order No. 719, the Commission required RTOs and ISOs to, among other things, accept bids from demand response resources in their markets for certain ancillary services on a basis comparable to other resources.24 The Commission also required each RTO and ISO “to reform or demonstrate the adequacy of its existing market rules to ensure that the market price for energy reflects the value of energy during an operating reserve shortage,”25 for purposes of encouraging existing generation and demand resources to continue to be relied upon during an operating reserve shortage, and encouraging entry of new generation and demand resources.26

24Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 47-49.

25Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194.

26Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 247.

13. Additionally, in recent years several RTOs and ISOs have instituted various types of demand response programs. While some of these programs are administered for reliability and emergency conditions, other programs allow wholesale customers, qualifying large retail customers, and aggregators of retail customers to participate directly in the day-ahead and real-time energy markets, certain ancillary service markets and capacity markets.27

27Other demand response programs allow demand response to be used as a capacity resource and as a resource during system emergencies or permit the use of demand response for synchronized reserves and regulation service.See, e.g., PJM Interconnection, L.L.C.,117 FERC ¶ 61,331 (2006);Devon Power LLC,115 FERC ¶ 61,340,order on reh'g,117 FERC ¶ 61,133 (2006),appeal pending sub nom. Maine Pub. Utils. Comm'nv.FERC,No. 06-1403 (D.C. Cir. 2007);New York Indep. Sys. Operator, Inc.,95 FERC ¶ 61,136 (2001);NSTAR Services Co.v.New England Power Pool,95 FERC ¶ 61,250 (2001);New England Power Pool and ISO New England, Inc.,100 FERC ¶ 61,287,order on reh'g,101 FERC ¶ 61,344 (2002),order on reh'g,103 FERC ¶ 61,304,order on reh'g,105 FERC ¶ 61,211 (2003);PJM Interconnection, L.L.C.,99 FERC¶ 61,227 (2002);California Independent System Operator Corp.,132 FERC ¶ 61,045 (2010).

14. To date, the Commission has allowed each RTO and ISO to develop its own compensation methodologies for demand response resources participating in its day-ahead and real-time energy markets. As a result, the levels of compensation for demand response vary significantly among RTOs and ISOs.28 For example, PJM Interconnection, L.L.C. (PJM) pays the LMP minus the generation and transmission portions of the retail rate.29 ISO New England Inc. (ISO-NE) and New York Independent System Operator, Inc. (NYISO) pay LMP when prices exceed a threshold level, with the levels differing between the RTOs.30 The Midwest Independent Transmission System Operator, Inc.'s (Midwest ISO) demand response programs31 pay LMP for demand response resources in the day-ahead and real-time energy markets.32 The California Independent System Operator Corporation (CAISO) pays LMP at pricing nodes, or sub-load aggregation points (Sub-LAP) in its Proxy Demand Resource program that allows qualifying resources to provide day-ahead and real-time energy.33 CAISO also provides for demand response resources to participate in its Participating Load program, which enables certain resources to provide curtailable demand in the CAISO market. CAISO pays nodal real-time LMP for its Participating Load program. The Southwest Power Pool, Inc. (SPP) has filed revisions to its tariff to facilitate demand response in the Energy Imbalance Service Market.34

28 See New England, Inc.,Docket No. ER09-1051-000;ISO New England, Inc.,Docket No. ER08-830-000;Midwest Indep. Transmission Sys. Operator, Inc.,Docket No. ER09-1049-000.

29 Seesections 3.3A.4 and 3.3A.5 (Market Settlements in the Real-Time and Day-Ahead Energy Markets) of the Appendix to Attachment K of the PJM Tariff.

30For example, under ISO-NE's Real-Time Price Response Program, the minimum bid is $100/MWh and a demand response resource is paid the higher of LMP or $100/MWh. For the Day-Ahead Load Response Program, the minimum offer level is calculated on a monthly basis and is the Forward Reserve Fuel Index ($/MMBtu) multiplied by an effective heat rate of 11.37 MMBtu/MWh. The maximum offer level is $1,000/MWh.Seesections III.E.2.1 and III.E.3.2 of Appendix E of the ISO New England Transmission, Markets and Services Tariff. NYISO implements a day-ahead demand response program by which resources bid into the market at a minimum of $75/MWh and can get paid the LMP.Seesection 4.2.2.9 (“Day-Ahead Bids from Demand Reduction Providers to Supply Energy from Demand Reductions”) of NYISO's Market Services Tariff.

31Midwest ISO FERC Electric Tariff characterizes Demand Response Resources (DRR) as either DRR-Type I or DRR-Type II. DRR-Type I are capable of supplying a specific quantity of energy or contingency reserve through physical load interruption. DRR-Type II are capable of supplying energy and/or operating reserves over a dispatchable range.Seesections 39.2.5A and 40.2.5 of the Tariff.

32 SeeCharges and Payments for Purchases and Sales for Demand Response Resources. Midwest ISO FERC Electric Tariff, section 39.3.2C.

33 Seesection 11.2.1.1 IFM Payments for Supply of Energy, CAISO FERC Electric Tariff. CAISO notes that for a Proxy Demand Resource that is made up of aggregated loads, the Resource is paid the weighted average of the LMPs of each pricing node where the underlying aggregate loads reside.See CAISO,132 FERC ¶ 61,045, at P 26 n.14 (2010).

34The Commission has directed SPP to report on ways it can incorporate demand response into its imbalance market.Southwest Power Pool, Inc.,128 FERC ¶ 61,085 (2009). As of September 1, 2010, SPP has submitted seven informational status reports regarding its efforts to address issues related to demand response resources. In orders addressing SPP's compliance with Order No. 719, the Commission also directed SPP to make another compliance filing addressing demand response participation in its organized markets.Southwest Power Pool, Inc.,129 FERC ¶ 61,163, at P 51 (2009). On May 19, 2010, SPP submitted revisions to its Open Access Transmission Tariff in Docket Nos. ER09-1050-004 and ER09-748-002 to comply with the Commission's requirements established in Order Nos. 719 and 719-A. These filings are pending before the Commission.

III. Procedural History

15. As noted above, the Commission issued the NOPR in this proceeding on March 18, 2010.35 The NOPR proposed to require RTOs and ISOs to pay the LMP in all hours for demand reductions made in response to price signals. The Commission sought comments on the compensation proposal and, in particular, on the comparability of generation and demand response resources; alternative approaches to compensating demand response in organized wholesale energy markets; whether payment of LMP should apply in all hours, and, if not, any criteria that should be used for establishing hours when LMP should apply; and whether to allow for regional variations concerning approaches to demand response compensation.36

35NOPR, FERC Stats. & Regs. ¶ 32,656.

36 SeeAppendix for a list of commenters.

16. After receiving the first round of comments, the Commission issued a Supplemental Notice of Proposed Rulemaking and Notice of Technical Conference (Supplemental NOPR) in this proceeding on August 2, 2010.37 The Supplemental NOPR sought additional comment on: Whether the Commission should adopt a net benefits test for determining when to compensate demand response providers, and, if so, what, if any, requirements should apply to the methods for determining net benefits; and what, if any, requirements should apply to how the costs of demand response are allocated. The Commission further directed Staff to hold a technical conference focused on these two issues, which occurred on September 13, 2010.38

37 Supplemental Notice of Proposed Rulemaking and Notice of Technical Conference,75 FR 47499 (Aug. 6, 2010), 132 FERC ¶ 61,094 (2010) (Supplemental NOPR).

38 SeeNotice of Technical Conference (Aug. 27, 2010).

IV. Discussion

17. Based upon the record in this proceeding, the Commission herein requires greater uniformity in compensating demand response resources participating in organized wholesale energy markets. This Final Rule also addresses the allocation of costs resulting from the commitment of demand response, directing that such costs be allocated among those customers who benefit from the lower LMP resulting from the demand response.

A. Compensation Level 1. NOPR Proposal

18. The NOPR proposed to require RTOs and ISOs to pay the LMP in all hours for demand reductions made in response to price signals. The NOPR sought to provide comparable compensation to generation and demand response providers, based on the premise that both resources provide a comparable service to RTOs and ISOs for purposes of balancing supply and demand and maintaining a reliable electricity grid.39 Also as stated in the NOPR, the proposed compensation level was designed to allow more demand response resources to cover their investment costs in demand response-related technology (such as advanced metering) and thereby facilitate their ability to participate in organized wholesale energy markets.40 The Commission sought comments on the compensation proposal and, in particular, on the comparability of generation and demand response resources; alternative approaches to compensating demand response in organized wholesale energy markets; whether payment of LMP should apply in all hours, and, if not, any criteria that should be used for establishing hours when LMP should apply; and whether to allow for regional variations concerning approaches to demand response compensation.

39NOPR, FERC Stats. & Regs. ¶ 32,656 at P 15.

40 Id.at P 16.

19. In the Supplemental NOPR, the Commission sought additional comments and directed staff to hold a technical conference regarding various net benefits tests. In particular, the Commission sought comment on:whether the Commission should adopt a net benefits test applicable in all or only some hours and what the criteria of any such test would be; how to define net benefits; what costs demand response providers and load serving entities incur and whether they should be included in a net benefits test; whether any net benefits methodology adopted should be the same for all RTOs and ISOs; proposed methodologies for implementing a net benefits test and the advantages and limitations of any proposed methodologies.41 The September 13, 2010 Technical Conference included an eleven-member panel discussion of net benefits tests representing a wide range of interests and viewpoints.42 The Commission subsequently received additional written comments addressing these issues.

41Supplemental NOPR, 132 FERC ¶ 61,094 at P 8-9.

42 SeeSept. 13, 2010 Tr.

2. Comments (a) Capability of Demand Response and Generation Resources To Balance Energy Markets

20. Various commenters address the comparability of demand response and generation resources for purposes of compensation in the organized wholesale energy markets. To begin, numerous commenters address the physical or functional comparability of demand response and generation, agreeing that an increment of generation is comparable to a decrement of load for purposes of balancing supply and demand in the day-ahead and real-time energy markets.43 Equating generation and demand response resources, Dr. Alfred E. Kahn states:

43DR Supporters Aug. 30, 2010 Comments (Kahn Affidavit at 2); Verso May 13, 2010 Comments at 3-4; Occidental May 13, 2010 Comments at 11; Viridity June 18, 2010 Comments at 5.

[Demand response] is in all essential respects economically equivalent to supply response * * * [so] economic efficiency requires * * * that it should be rewarded with the same LMP that clears the market. Since [demand response] is actually—and not merely metaphorically—equivalent to supply response, economic efficiency requires that it be regarded and rewarded, equivalently, as a resource proffered to system operators, and be treated equivalently to generation in competitive power markets. That is, all resources—energy saved equivalently to energy supplied—* * * should receive the same market-clearing LMP in remuneration.44

44DR Supporters August 30, 2010 Reply Comments (Kahn Affidavit at 2 (footnote omitted)).

Indeed, some commenters believe that, from a physical standpoint, demand response can provide superior services to generation, such as providing a quick response in meeting system requirements and service without having to construct major new facilities.45 Occidental asserts that the fungibility of demand response and generation output creates greater operational flexibility that, in turn, offers RTOs and ISOs multiple options to solve system issues both in energy and ancillary service markets, and that the fungible nature of demand response and generation supports comparable compensation for each as proposed in the NOPR.46

45Verso May 13, 2010 Comments at 3-4; Alcoa May 13, 2010 Comments at 9.

46Occidental May 13, 2010 Comments at 11.

21. Viridity states that attempts to distinguish the physical characteristics of generation and demand response ignore bid-based security-constrained economic dispatch as the foundation for LMP and are based on the assumption that the value of load management on the grid is limited to periods when the system is stressed,i.e.,traditional “super peak shaving.” Viridity states that, while these arguments might have been valid 15 years ago, today competitive markets can offer proactively-managed load control and comparable and non-discriminatory treatment of load-based energy resources. Therefore, Viridity asserts that all resources should be paid LMP if the grid operator accepts their bid to achieve grid balance.47

47Viridity June 18, 2010 Comments at 5.

22. At the same time, other commenters argue that generation and demand response are not physically equivalent, pointing out that demand response reduces consumption, whereas generators serve consumption.48 They argue that a MW reduction in demand does not turn on the lights.49 EPSA adds that a load reduction does not provide electrons to any other load and, instead, allows the marginal electron to serve a different customer.50 Some commenters assert that a power system can function solely and reliably on generating plants and without any reliance on demand response, while the system cannot rely exclusively on demand response because demand response by itself cannot keep the lights on. Ultimately, some commenters point out, megawatts produced by generators need to be placed on the system in order for power to flow.51 Battelle additionally argues that a reduction in consumption is not exactly the same as an increase in production, because elastic demand often comes with attendant future consequences, such as rebound, by virtue of substitution in time.52

48ISO-NE May 13, 2010 Comments at 3.

49 See, e.g.,APPA May 13, 2010 Comments at 12; Capital Power May 13, 2010 Comments at 2.

50EPSA May 13, 2010 Comments at 72.

51 See, e.g.,PSEG May 13, 2010 Comments at 8.

52Battelle May 13, 2010 Comments at 3.

23. Some commenters who argue that the physical characteristics of demand response are not comparable to generation frame their arguments in terms of the ability of the system operator to call on demand response and generation resources to provide balancing energy. They argue that generation resources provide superior service to demand response providers, positing that demand response is not intended for long periods of balancing needs,53 and that, moreover, contracts with demand response providers limit the number of hours and times a customer may be called upon to curtail. For example, ODEC asserts that the degree of physical comparability depends on the extent to which demand response resources can be dispatched similar to a generator.54 Calpine adds that traditional generators provide system support features that demand response cannot, such as ancillary services including governor response or reactive power voltage support, which are necessary for reliable operation of the electric system.55

53AEP May 13, 2010 Comments at 7-8.

54ODEC May 13, 2010 Comments at 12.

55Calpine May 13, 2010 Comments at 4-5.

24. Numerous commenters also address the comparability of demand response and generation in economic terms. For example, EEI states that, in finance terms, the demand response product is, unlike generation, essentially an unexercised call option on spot market energy, and the value of that option is well-established in finance theory as the value of the resource (LMP) minus the “strike price,” which EEI contends in this case is the retail tariff rate.56 EEI and like-minded commenters support, therefore, alternative compensation for demand response to equal LMP minus the generation (or G) component of the retail rate.57 They posit that payment ofLMP without an offset for some portion of the retail rate does not send the proper economic signal to providers of demand response, because it fails to take into account the retail rate savings associated with demand response, and thereby overcompensates the demand response provider. As described by Dr. William W. Hogan on behalf of EPSA, this is sometimes called a double-payment for demand reductions, because demand response providers would “receive” both the cost savings from not consuming an increment of electricity at a particular price, plus an LMP payment for not consuming that same increment of electricity.58 Viewing LMP as a double-payment, these commenters argue that paying LMP will result in more demand response than is economically efficient.59 For example, Dr. Hogan states that paying LMP might motivate a company to shut down even though the benefits of consuming electricity outweigh the cost at LMP.60 Indeed, P3 argues that compensation in excess of LMP-G is unjust and unreasonable, because such a payment level imposes costs on customers that are not commensurate with benefits received.61

56EEI May 13, 2010 Comments at 4-5.See alsoRobert L. Borlick May 13, 2010 Comments at 4. Mr. Borlick argues that the correct price is LMP minus the Marginal Foregone Retail Rate (MFRR), describing the economically efficient price that should be paid to a demand response provider as “its offer price minus the price in its retail tariff at which it would have purchased the curtailed energy.” Mr. Borlick asserts that this amount accurately represents the forgone opportunity costs that result when a demand response provider reduces its load.Id.

57 SeeMay 13, 2010 Comments of: APPPA; AEP; The Brattle Group; Calpine; ConEd; Consumers Energy; CPG; Detroit Edison; Direct Energy; Dominion; Duke Energy; Edison Mission; EEI; EPSA; Exelon; FTC; GDF; NYISO on behalf of theISO RTO Council; ICC; IPPNY; Indicated New York TOs; IPA; ISO-NE; Midwest TDUs; Mirant; Midwest ISO TOs; NEPGA; NYISO; ODEC; OMS; PJM; PJM IMM; P3; Potomac Economics; PG&E; Ohio Commission; Robert L. Borlick; Roy Shanker; and RRI Energy.

58 SeeAttachment to Answer of EPSA, Providing Incentives for Efficient Demand Response, Dr. William W. Hogan, Oct. 29, 2009, submitted in Docket No. EL09-68-000.

59EPSA May 13, 2010 Comments at 23.See alsoMay 13, 2010 Comments of APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New York Commission at 5; PJM at 6; PSEG at 5; and Potomac Economics at 6-8.

60Attachment to Answer of EPSA, Providing Incentives for Efficient Demand Response, Dr. William W. Hogan, Oct. 29, 2009, submitted in Docket No. EL09-68-000. In Dr. Hogan's view, supply should produce when the price of electricity exceeds its cost of production and demand should decline to consume when the costs in terms of convenience of delaying use are less than the price of electricity.

61P3 June 14, 2010 Comments at 2, 7-8.

25. ISO-NE argues that paying full LMP to demand response providers without taking into account the bill savings produced by demand response provides a significant financial incentive to dispatch demand response with marginal costs exceeding LMPs. By dispatching higher-cost demand response, ISO-NE asserts, lower-cost generation resources are displaced.62 At the same time, ISO-NE argues, generation is not dispatched and paid for only when the generation reduces LMP—generation is dispatched and paid for when it is cost-effective.63

62ISO-NE May 13, 2010 Comments at 3-4.

63 Id.at 28.

26. Dr. Hogan further disputes arguments equating a MW of energy supplied to a MW of energy saved on economic grounds. Dr. Hogan draws a distinction between reselling something that one has purchased, and selling something that one would have purchased without actually purchasing it. Dr. Hogan argues that from the perspective of economic efficiency and welfare maximization, the aggregate effect of demand response is a wash producing no economic net benefit. Dr. Hogan asserts that Commission policy citing the benefits of price reduction in support of demand response compensation would amount to no less than an application of regulatory authority to enforce a buyers' cartel. He states that the Commission has been vigilant and aggressive in preventing buyers and sellers from engaging in market manipulation to influence prices, and it would be fundamentally inconsistent for the Commission to design demand response compensation policies that coordinate and enforce such price manipulation.

27. Dr. Hogan argues that the ideal and economically efficient solution regarding demand response compensation is to implement retail real-time pricing at the LMP, thereby eliminating the need for demand response programs. Realizing that this is unattainable at the present time, Dr. Hogan goes on to propose a next-best solution, which he believes is to pay demand response compensation in the amount of LMP-G, or some amount that simulates explicit contract demand response (such as “buy-the-baseline” approach discussed below). These options, he argues, more than paying LMP, better support notions of comparability between demand response resources and generation.64

64Hogan Affidavit, ISO RTO Council May 13, 2010 Comments at 5.

28. The New York Commission, however, argues that requiring payment of LMP-G would result in an administrative burden of tracking retail rates for the multiple utilities, ESCOs and power authorities and create undue confusion for retail customers and administrative difficulties for State commissions and ISOs and RTOs.65

65New York Commission May 13, 2010 Comments at 8.

29. Consistent with Dr. Hogan's arguments, some commenters assert that demand response providers should actually own or pay for electricity prior to, what commenters characterize as, an effective reselling of the electricity back to the market in the form of demand response. For example, these commenters suggest that the demand response provider purchase the power in the day-ahead market and resell it in the real-time markets.66 EPSA argues that there must be some purchase requirement or representative offset to allow a demand response provider to “sell” a commodity that it owns to the ISO or RTO.67 EPSA argues that such a requirement would send an efficient price signal, reduce incentives for gaming the system, and help address difficulties with measurement and verification of a demand reduction. EPSA highlights an ISO-NE IMM recommendation that, if the Commission permits LMP payment, it should also adopt a “buy-the-baseline” approach requiring demand response resources to purchase an expected amount of energy consumption in the day-ahead energy market and subsequently sell any demand reduction from that level in the real-time market.68

66 See, e.g.,ISO-NE IMM May 13, 2010 Comments at 4-5; Midwest ISO TOs May 13, 2010 Comments at 14; PJM May 13, 2010 Comments at 5; and Duke Energy May 13, 2010 Comments at 2.

67EPSA June 30, 2010 Comments at 3.

68EPSA June 30, 2010 Comments at 23.

30. Viridity, on the other hand, argues that forcing customers to buy and then resell electricity will lead to too little demand response and that adopting a “buy-the-baseline” approach would constitute an inappropriate exercise of Commission authority to effectively force parties into contracts. Viridity and DR Supporters state that any characterization of demand response as a purchase and then resale of energy is erroneous69 and based on the flawed assumption that demand response resources are reselling energy. They state that the description of demand response as a reselling of energy has been correctly rejected by the Commission inEnergyConnect,where the Commission stated that it was establishing a policy of treating demand response as a service rather than a purchase and sale of electric energy.70

69Viridity Energy June 18, 2010 Comments at 25.

70DR Supporters Aug. 30, 2010 Reply Comments at 10 (citingEnergyConnect, Inc.,130 FERC ¶ 61,031 at P 30-31 (2010)).

31. DR Supporters further argues that, despite claims to the contrary, paying full LMP to demand response providers does not constitute a subsidy for demand response any more than the remunerations of generators for the power that they sell. As Dr. Kahn states:

Does this plan involve double compensation, as [Dr.] Hogan asserts, at the expense of power generators—of successfulbidders promising to induce efficient demand curtailment and of consumers induced to practice it? Certainly not: The decrease in the revenue of the generators is (and consequent savings by consumers are) matched by the savings in their (marginal) costs of generating that power; the successful bidders for the opportunity to induce that consumer response are compensated for the costs of those efforts by the pool, whose (marginal) costs they save by assisting consumers to reduce their purchases.71

71DR Supporters Aug. 30, 2010 Reply Comments, Kahn Affidavit at 10.

32. Viridity further disputes Dr. Hogan's argument that payment of LMP for demand response will distort an otherwise optimal market. Viridity posits that such arguments ignore dislocations in the wholesale power markets, the existence of market power that must be mitigated, imperfect information available to customers, barriers to entry and uneconomic resources dispatched to fulfill must-run requirements.72 Viridity further states that Dr. Hogan's arguments fail to acknowledge the limits of the Commission's jurisdiction and widespread dislocations and distortions in virtually all economic aspects of relevant energy markets (including fuels, facilities, pricing, environmental attributes, information and participation) and fail to account for any market benefits of demand response.73 Finally, Viridity argues that Dr. Hogan's arguments fail to reflect the many complex interactions between price, equipment operational requirements, and customer processes, which point to a complex demand response decision.74

72Viridity June 18, 2010 Comments at 13 (“Importantly, Dr. Hogan (and others) in opposing the proposed rulemaking fails to acknowledge the limits of the Commission's jurisdiction, and wide spread dislocations and distortions in virtually all economic aspects of relevant energy markets (including fuels, facilities, pricing, environmental attributes, information and participation).” (Affidavit of John C. Tysseling, PhD)).

73Viridity Reply Comments at 13.

74Viridity Reply Comments at 14.

33. In addition to physical and economic comparability, some commenters contrast the environmental effects of generation and demand response resources. EDF notes that current market prices fail to internalize environmental externalities—including toxic air pollution, greenhouse gas pollution, and land and water use impacts—and other social costs. EDF asserts that the social impact of these environmental externalities is especially acute at peak times, positing that generation sources used for marginal supply at such times (“peaker plants”) are among the oldest, dirtiest, and most inefficient in the fleet.75 The American Clean Skies Foundation contends that fossil-fuel generators are typically mispriced because wholesale prices radically understate the full environmental and health costs associated with such generators.76 Indeed, some commenters, such as Alcoa, argue that because demand response does not result in the external costs associated with generation (e.g.,greenhouse gas emissions), instead resulting in less greenhouse gas emissions than generation, it should be compensated at more than LMP.77

75EDF Oct. 13, 2010 Comments at 2.

76American Clean Skies Foundation May 13, 2010 Comments at 4.

77Alcoa May 13, 2010 Comments at 9.

34. Taking the opposite view concerning environmental externalities, EPSA states that paying LMP for demand response will merely encourage load to switch to off-grid power (or behind-the-meter generation), while still being compensated, and that such behind-the-meter generation produces more greenhouse gases and other air emissions than electricity from the regional energy market.78

78EPSA May 13, 2010 Comments at 60.

35. Some commenters discuss comparability of generation and demand response in terms of the market rules that apply to each resource, arguing that both resources should be comparably compensated only if the same rules for participation apply to both resources, and both resources are held to the same standards for dispatchability.79 They also argue that similar penalty structures should apply to demand response resources as apply to generation, and that demand response participation must be subject to market monitoring.80 Calpine adds that to the extent demand response resources are used and treated on par with generators for purposes of compensation, they should be subject to the same performance testing, penalties, and other similar requirements as generators.81

79ODEC May 13, 2010 Comments at 12; Westar May 13, 2010 Comments at 5-6.

80 Id.

81Calpine May 13, 2010 Comments at 5.

36. Some commenters address the comparability of demand response providers and generators in terms of maintaining system reliability. PIO argues that reductions in consumption provide additional reliability.82 According to the NEMA, North American Electric Reliability Corporation (NERC) standards suggest that, from a reliability perspective, load reductions are equivalent or even superior to generator increases for balancing purposes. For example, while specific to the Western Interconnection, BAL-002-WECC-1 lists interruptible load as comparable to generation deployable within 10 minutes.83 EPSA maintains that demand response resources are not full substitutes based on the nature of their participation and the rules applicable to each resource in the energy markets, pointing out, for example, that, unlike generators, demand response providers are not subject to regional and NERC mandatory reliability standards.84

82PIO May 13, 2010 Comments at 8.

83NEMA May 13, 2010 Comments at 2.

84EPSA May 13, 2010 Comments at 7.

37. On the other hand, PSEG argues that a MW of demand response does not make the same contribution towards system reliability as a MW of generation, because demand response committed as a capacity resource is only required to perform for a limited numb