# Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2016-28320 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** December 5, 2016 - **Citation:** 81 FR 87770 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM16-5-000; Order No. 831] Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators AGENCY: Federal Energy Regulatory Commission. ACTION: Final rule. SUMMARY: The Federal Energy Regulatory Commission is revising its regulations to address incremental energy offer caps. We require that each regional transmission organization (RTO) and independent system operator (ISO): Cap each resource's incremental energy offer at the higher of $1,000/megawatt-hour (MWh) or that resource's verified cost-based incremental energy offer; and cap verified cost-based incremental energy offers at $2,000/MWh when calculating locational marginal prices (LMP). Further, we clarify that the verification process for cost-based incremental offers above $1,000/MWh should ensure that a resource's cost-based incremental energy offer reasonably reflects that resource's actual or expected costs. This Final Rule will improve price formation by reducing the likelihood that offer caps will suppress LMPs below the marginal cost of production, while compensating resources for the costs they incur to serve load, by enabling RTOs/ISOs to dispatch the most efficient set of resources when short-run marginal costs exceed $1,000/MWh, by encouraging resources to offer supply to the market when it is most needed, and by reducing the potential for seams issues. DATES: Effective Date: This rule will become effective February 21, 2017. FOR FURTHER INFORMATION CONTACT: Emma Nicholson (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8846, emma.nicholson@ferc.gov Pamela Quinlan (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6179, pamela.quinlan@ferc.gov Anne Marie Hirschberger (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8387, annemarie.hirschberger@ferc.gov SUPPLEMENTARY INFORMATION: Order No. 831 Final Rule Table of Contents Paragraph numbers I. Introduction 1 II. Background 7 A. Offer Caps in RTOs/ISOs 10 B. Offer Caps Waivers and Tariff Changes 14 III. Need for Reform 15 A. Comments 16 1. Comments That Support the Preliminary Finding That Current Offer Caps are Unjust and Unreasonable 16 2. Comments that Oppose Reforming Current Offer Caps 20 3. Generally Applicable Offer Cap Reforms 27 B. Determination 34 IV. Offer Cap Reforms 42 A. Offer Cap Structure 44 1. NOPR Proposal 44 2. Comments 45 3. Determination 77 B. Cost Verification 96 1. NOPR Proposal 96 2. Comments 98 3. Determination 139 C. Resource Neutrality 148 1. NOPR Proposal 148 2. Comments 149 3. Determination 156 V. Other Issues 160 A. Virtual Transactions 160 1. Comments 161 2. Determination 172 B. External Transactions 178 1. Comments 179 2. Determination 192 VI. Other Comments 199 A. Verification Requirement Details 200 1. Comments 200 2. Determination 207 B. Impact of Offer Cap Reforms on Other Market Elements 209 1. Comments 210 2. Determination 213 VII. Requests Beyond the Scope of this Proceeding 214 A. Comments 214 B. Determination 218 VIII. Information Collection Statement 219 IX. Regulatory Flexibility Act Certification 223 X. Environmental Analysis 225 XI. Document Availability 226 XII. Effective Date and Congressional Notification 229 Regulatory Text APPENDIX: List of Short Names/Acronyms of Commenters I. Introduction 1. In this Final Rule, the Federal Energy Regulatory Commission (Commission) finds that current regional transmission organization (RTO) and independent system operator (ISO) offer caps on incremental energy offers 1 (offer cap) are not just and reasonable for the reasons discussed below. To remedy these unjust and unreasonable rates, we require, pursuant to section 206 of the Federal Power Act, 2 that each RTO/ISO: (1) Cap each resource's incremental energy offer at the higher of $1,000/megawatt-hour (MWh) or that resource's verified cost-based incremental energy offer; and (2) cap verified cost-based incremental energy offers at $2,000/MWh when calculating locational marginal prices (LMP) (hard cap). 3 Further, we clarify that the verification process for cost-based incremental offers above $1,000/MWh should ensure that a resource's cost-based incremental energy offer reasonably reflects that resource's actual or expected costs. 1 The incremental energy offer is the portion of a resource's energy supply offer that varies with output or level of demand reduction. 2 16 U.S.C. 824e (2012). 3 In this proceeding, a hard cap refers to an upper limit on the incremental energy offers that RTOs/ISOs can use to calculate LMPs. The hard cap does not limit the cost-based incremental energy offers that a market participant may submit to the RTO/ISO. 2. We reach this conclusion for several reasons. First, offer caps in some RTOs/ISOs may prevent a resource from recouping its short-run marginal costs by not permitting that resource to include all of its short-run marginal costs within its incremental energy offer. Second, current offer caps in some RTOs/ISOs are likely to suppress LMPs below the marginal cost of production during periods when fuel costs increase dramatically. Third, when several resources have short-run marginal costs above $1,000/MWh but are unable to reflect those costs within their incremental energy offers due to the offer cap, the RTO/ISO is unable to dispatch the most efficient set of resources because it will not be able to distinguish among the resources' actual costs. Finally, the $1,000/MWh offer cap in some RTOs/ISOs may discourage resources with short-run marginal costs above $1,000/MWh from offering supply to the RTO/ISO, even though the market may be willing to purchase that supply. 4 To remedy these problems, we are setting forth requirements for each RTO/ISO regarding the offer cap in this Final Rule. We believe generic action is appropriate to avoid the creation of seams that would result from different offer caps in adjacent RTO/ISO markets. 4 Many resources are subject to must-offer requirements in either the day-ahead or real-time markets. These offer cap reforms ensure that such a resource has an economic incentive that matches its tariff obligation and also provide an economic incentive to those resources that are not subject to a must-offer requirement. 3. We have modified the proposal in the Notice of Proposed Rulemaking (NOPR) to include a $2,000/MWh hard cap for the purposes of calculating LMPs. While the offer cap proposed in the NOPR would address the concerns identified above, we are convinced by commenters that the absence of a hard cap creates practical concerns that must be addressed. First, several commenters note that RTOs/ISOs and/or Market Monitoring Units may have imperfect information about resource short-run marginal costs, which can create challenges for the proposed requirement to verify cost-based incremental energy offers above $1,000/MWh prior to the market clearing process. Additionally, as noted by market monitors, the dynamics of natural gas spot market prices during periods when they rise to levels that could result in the short-run marginal costs of some natural gas-fired resources exceeding $1,000/MWh can make verification challenging, particularly verification of expected costs. Thus, while a hard cap may diminish the ability to fully address the shortcomings of current offer caps identified above in all circumstances, we find that, on balance, a hard cap is necessary to reasonably limit the adverse impact that any imperfect information during the verification process could have on LMPs. 4. The goals of the price formation proceeding are to: (1) Maximize market surplus for consumers and suppliers; (2) provide correct incentives for market participants to follow commitment and dispatch instructions, make efficient investments in facilities and equipment, and maintain reliability; (3) provide transparency so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system; and (4) ensure that all suppliers have an opportunity to recover their costs. 5 5 See Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators, Notice Inviting Post-Technical Workshop Comments, Docket No. AD14-14-000, at 1 (Jan. 16, 2015) (Notice Inviting Comments); Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators, Notice, Docket No. AD14-14-000 (June 19, 2014) (Price Formation Notice). 5. The reforms adopted in this Final Rule advance two of the Commission's goals with respect to price formation. First, the reforms will result in LMPs that are more likely to reflect the true marginal cost of production when resources' short-run marginal costs exceed $1,000/MWh. In the short run, LMPs that reflect the short-run marginal costs of production are particularly important during high price periods because they provide a signal to consumers to reduce consumption and a signal to suppliers to increase production or to offer new supplies to the market. In the long run, LMPs that reflect the short-run marginal cost of production are important because they inform investment decisions. Second, the reforms will give resources the opportunity to recover their short-run marginal costs, thereby encouraging resources to participate in RTO/ISO energy markets. Adequate investment in resources and resource participation in RTO/ISO energy markets ensure adequate and reliable energy for consumers. The benefits summarized above and discussed in detail below would ultimately help to ensure just and reasonable rates. 6. As discussed below, we require each RTO/ISO to submit a filing with the tariff changes needed to implement this Final Rule within 75 days of the Final Rule's effective date. II. Background 7. In June 2014, the Commission initiated a proceeding, in Docket No. AD14-14-000, to evaluate issues regarding price formation in the energy and ancillary services markets operated by RTOs/ISOs. 6 In the notice initiating that proceeding, the Commission stated that there may be opportunities for the RTOs/ISOs to improve the energy and ancillary services price formation process. As set forth in that notice, LMPs and market-clearing prices used in energy and ancillary services markets ideally “would reflect the true marginal cost of production, taking into account all physical system constraints, and these prices would fully compensate all resources for the variable cost of providing service.” 7 6 Price Formation Notice, Docket No. AD14-14-000. 7 Price Formation Notice, Docket No. AD14-14-000 at 2. 8. In the instant proceeding, on January 21, 2016, the Commission issued a NOPR proposing to require that each RTO/ISO: (1) Cap each resource's incremental energy offer to the higher of $1,000/MWh or that resource's verified cost-based incremental energy offer; and (2) use verified cost-based incremental energy offers above $1,000/MWh to calculate LMPs. 8 8 Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, 81 FR 5951 (Feb. 4, 2016), FERC Stats. & Regs. ¶ 32,714, at P 3 (2016) (NOPR). 9. The Commission also sought comments on the NOPR proposal regarding: (1) Whether a hard cap on cost-based incremental energy offers used for purposes of calculating LMPs should be included in any Final Rule in this proceeding and, if so, whether the hard cap should equal $2,000/MWh or another value; (2) the ability of the Market Monitoring Unit or RTO/ISO to verify the costs underlying incremental energy offers above $1,000/MWh prior to the day-ahead or real-time market clearing process, including whether the verification of physical offer components is also necessary; (3) whether the Market Monitoring Unit or RTO/ISO may need additional information to ensure that all short-run marginal cost components, such as risk or opportunity costs that are often difficult to quantify, are accurately reflected in a resource's cost-based incremental energy offer, and whether an adder is appropriate; (4) whether the Market Monitoring Unit or RTO/ISO may need additional information or the authority to require revisions or corrections to cost-based incremental energy offers to ensure that cost-based incremental energy offers are accurate reflections of a resource's short-run marginal cost; (5) whether the proposal should apply to imports and whether a cost verification process for import transactions is feasible; (6) whether excluding virtual transactions above $1,000/MWh could limit hedging opportunities, present opportunities for manipulation or gaming, or create market inefficiencies; and (7) the impact the proposal would have on seams. 9 9 Id. P 73. A. Offer Caps in RTOs/ISOs 10. Supply offers in day-ahead and real-time energy markets consist of both financial and physical components. The financial components of a supply offer are denominated in dollars ( e.g., $/start and $/MWh) and represent the costs underlying a resource's offer to supply electricity in a given day-ahead or real-time interval. The physical components of a supply offer, which are not denominated in dollars, describe the resource's physical operating parameters. These include, for example, a resource's minimum and maximum operating limits in a given day-ahead or real-time interval, and are denominated in MW, MWh, time, or some other unit. 11. This Final Rule addresses the incremental energy offer component of a resource's supply offer, which is a financial component consisting of costs that vary with a resource's output or level of demand reduction. Incremental energy offers typically consist of a supply curve made up of multiple price-quantity pairs that indicate the price, expressed in $/MWh, that a resource is willing to accept to produce a given quantity of energy. 12. All six Commission-jurisdictional RTOs/ISOs have at one time imposed a $1,000/MWh cap on incremental energy offers. 10 The offer cap remains at $1,000/MWh in CAISO, ISO-NE., MISO, NYISO, and SPP, and resources in these RTOs/ISOs may not submit incremental energy offers above $1,000/MWh. As discussed further below, resources in PJM may submit incremental energy offers above $1,000/MWh provided they are cost-based, but PJM applies a hard cap that limits incremental energy offers to $2,000/MWh when calculating LMPs. 11 10 See, e.g., California Independent System Operator Corporation, eTariff, 39.6.1.1 (11.0.0); ISO New England Inc., Transmission, Markets and Services Tariff, Market Rule 1, III.1.10.1A(c)(iv), III,1.10.IA(d)(iv), III.2.6(b)(i), and III.A.15.1(b) (46.0.0); Midcontinent Independent System Operator, Inc., FERC Electric Tariff, Module D 39.2.5 (35.0.0), 39.2.5A (34.0.0), 39.2.5B (34.0.0), 40.2.5 (35.0.0), 40.2.6 (35.0.0) and 40.2.7 (33.0.0); New York Independent System Operator, Inc., NYISO Tariffs, NYISO Markets and Services Tariff, 21.4 and 21.5.1 (7.0.0); PJM Interconnection, L.L.C., Intra-PJM Tariffs, OATT, Tariff Operating Agreement, Attachment K, Appendix, 1.10.1A(d) (24.0.0); Southwest Power Pool, Inc., OATT, Sixth Revised Volume No. 1, Attachment AE, Section 4.1.1 (2.0.0). 11 PJM Interconnection, L.L.C., 153 FERC ¶ 61,289, at P 25 (2015) (PJM 2015 Offer Cap Order). 13. While the current offer caps restrict the incremental energy offers, one of the components used to set LMP, they do not limit LMPs to the level of the offer caps because the addition of the congestion and loss components of the LMP can result in LMPs that exceed the offer cap. Scarcity or shortage pricing and emergency purchases can also cause LMPs to exceed the offer cap. B. Offer Caps Waivers and Tariff Changes 14. As described in the NOPR, after the extreme weather experienced during the winter of 2013/14, dubbed the “Polar Vortex”, PJM, NYISO, and MISO filed various requests to either temporarily or permanently revise their respective offer caps. 12 During the winter months of 2014, the Commission approved requests to temporarily waive tariff provisions related to offer caps in NYISO 13 and PJM. 14 In the following winter of 2014/15, the Commission approved temporary changes to the PJM tariff and temporarily waived some MISO tariff provisions to address issues with the offer caps in the PJM and MISO energy markets. 15 During the winter of 2015/16, PJM and MISO again filed requests to modify their respective offer caps. On December 11, 2015, the Commission accepted tariff revisions in PJM that would raise the cap on cost-based incremental energy offers to $2,000/MWh for purposes of calculating LMPs. 16 The Commission also granted MISO's request to temporarily waive tariff provisions related to its $1,000/MWh offer cap. 17 MISO recently filed another request to temporarily waive tariff provisions related to its offer cap for the upcoming winter of 2016/17. 18 12 NOPR, FERC Stats. & Regs ¶ 32,714 at PP 13-17. 13 N.Y. Indep. Sys. Operator, Inc., 146 FERC ¶ 61,061, at PP 2-4 (2014). 14 PJM filed concurrently two tariff waiver requests related to its offer cap. In its first request, which the Commission granted for the January 24-February 10, 2014 period, PJM requested that certain resources with cost-based offers above $1,000/MWh receive uplift payments to recoup those costs. See PJM Interconnection, L.L.C., 146 FERC ¶ 61,041, at P 2 (PJM 2014 Waiver Order I), order on reh'g, 149 FERC ¶ 61,059 (2014). In its second request, which the Commission granted for the February 11-March 31, 2014 period, PJM requested that certain resources be allowed to submit cost-based incremental energy offers in excess of $1,000/MWh, with no cap on cost-based offers. See PJM Interconnection, L.L.C., 146 FERC ¶ 61,078, at PP 3-4 (2014) (PJM 2014 Offer Cap Order II). 15 The temporary revisions to the PJM tariff were accepted for the January 16, 2015 through March 31, 2015 period. See PJM Interconnection, L.L.C., 150 FERC ¶ 61,020, at P 5 (2015) (PJM 2014/15 Offer Cap Order). The temporary waiver of the MISO tariff provisions was granted for December 20, 2014 through April 30, 2015 period. See Midcontinent Indep. Sys. Operator, Inc., 150 FERC ¶ 61,083, at P 3 (2015) (MISO 2014/15 Offer Cap Order). 16 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 25. The tariff provisions related to the offer cap do not have a sunset date. 17 Midcontinent Indep. Sys. Operator, Inc., 154 FERC ¶ 61,006, at P 1 (2016) (MISO 2015/16 Offer Cap Order). This waiver was granted for the January 1, 2016 through April 30, 2016 period. 18 Midcontinent Indep. Sys. Operator, Inc., Transmittal, Docket No. ER16-2685-000. III. Need for Reform 15. In the NOPR, the Commission preliminarily found that the $1,000/MWh offer caps currently in effect in some RTOs/ISOs 19 are unjust and unreasonable for four reasons. 20 First, some current RTO/ISO offer caps may prevent a resource from recouping its short-run marginal costs by not permitting that resource to reflect its short-run marginal costs within its incremental energy offer. Second, current offer caps may suppress LMPs below the marginal cost of production. Third, when several resources have short-run marginal costs above $1,000/MWh but are unable to reflect those costs within their incremental energy offers due to the offer cap, the RTO/ISO may not dispatch the most efficient set of resources because it will not be able to distinguish between the resources' actual costs. Finally, the $1,000/MWh offer cap in some RTOs/ISOs may discourage resources with short-run marginal costs above $1,000/MWh from offering supply to the RTO/ISO, even though the market may be willing to purchase that supply. 21 We believe generic action is appropriate to avoid the creation of seams that would result from different offer caps in adjacent RTO/ISO markets. As described below, based on our analysis of the record, we adopt the preliminary findings in the NOPR and conclude that the current offer caps in RTOs/ISOs are unjust and unreasonable. 19 Specifically CAISO, ISO-NE., MISO, NYISO, and SPP. See supra n.10. 20 See NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 43-47. 21 Id. PP 44-47. A. Comments 1. Comments That Support the Preliminary Finding That Current Offer Caps are Unjust and Unreasonable 16. Several commenters, for various reasons, support the Commission's preliminary finding in the NOPR that existing offer caps in RTOs/ISOs are unjust and unreasonable, 22 and others express general or conditional support for the NOPR. 23 Some commenters agree that the $1,000/MWh offer cap prevents resources from recovering their short-run marginal costs. 24 For example, Direct Energy states that generator cost assurance is key to maintaining reliability because it ensures that resources will have the incentive to follow RTO/ISO dispatch instructions when called upon by the RTO/ISO, without concern for receiving compensation below their short-run costs. 25 Six Cities states that exceptional circumstances may give rise to marginal costs for specific resources that exceed $1,000/MWh and those resources should have an opportunity to recover their actual costs of production. 26 22 See generally CEA Comments at 3-4; Direct Energy Comments at 2-3; Exelon Comments at 5-7; PJM/SPP Comments at 1-2; EEI Comments at 3-4; Competitive Suppliers Comments at 4, 6, 7-15; Ohio Commission Comments at 4. A list of commenters and the abbreviated names used for them in this Final Rule appears in the Appendix. 23 See generally Dominion Comments at 3; EEI Comments at 3-5; Golden Spread Comments at 1; Midcontinent Joint Consumer Advocates Comments at 2; MISO Comments at 1; NESCOE Comments at 1; New Jersey Commission Comments at 1; NY Transmission Owners Comments at 2; NYISO Comments at 2; OMS Comments at 2; OPSI Comments at 10; PJM/SPP Comments at 1; Potomac Economics Comments at 1; Powerex Comments at 6; Six Cities Comments at 2. 24 CEA Comments at 4; Direct Energy Comments at 2-3; OMS Comments at 2; Six Cities Comments at 2. 25 Direct Energy Comments at 2. 26 Six Cities Comments at 2. 17. Several commenters support the Commission's preliminary finding that existing RTO/ISO offer caps should be reformed because they can suppress LMPs below the marginal cost of production. 27 For example, PJM/SPP 28 state that the current offer caps could undermine market efficiency by preventing legitimate incremental energy offers above $1,000/MWh, which they state has occurred in some parts of the country, because LMPs that fail to reflect the cost of serving demand are inefficient. 29 Competitive Suppliers assert that while the costs of the marginal resources have not frequently exceeded $1,000/MWh, the impact of the $1,000/MWh offer cap is not trivial because artificially suppressing day-ahead or real-time LMPs during those few intervals can prevent economic outcomes that will support reliability and motivate consumers to reduce consumption during stressed system conditions. 30 Midcontinent Joint Consumer Advocates support changing the offer cap because incremental energy costs would only exceed $1,000/MWh in extreme conditions. 31 27 See generally CEA Comments at 3-4; Competitive Suppliers Comments at 9-13; Exelon Comments at 5-7; EEI Comments at 3-5; PJM Power Providers Comments at 1-2; PJM/SPP Comments at 1-2; Powerex Comments at 6. 28 “PJM/SPP” indicates comments filed jointly by PJM and SPP. PJM and SPP also make individual comments within their joint filing. 29 PJM/SPP Comments at 1-2 (citing PJM, Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather Events (May 8, 2014), available at http://www.pjm.com/~/media/committeesgroups/task-forces/cstf/20140509/20140509-item-02-cold-weather-report.ashx ). 30 Competitive Suppliers Comments at 9. 31 Midcontinent Joint Consumer Advocates Comments at 3-4. 18. Other commenters agree with the Commission's preliminary finding that the $1,000/MWh offer cap should be reformed because it can discourage a resource with costs above the offer cap from offering its supply to the RTO/ISO, even though the market may be willing to purchase that supply. 32 For example, OMS states that when the (primarily fuel) cost to generate electricity is unusually high, the current $1,000/MWh offer cap can limit the willingness of resources to offer into the day-ahead and real-time markets. 33 32 See generally CEA Comments at 3-4; Competitive Suppliers Comments at 13; OMS Comments at 2; Powerex Comments at 6. 33 OMS Comments at 2. 19. CEA and EEI express general support for the Commission's preliminary finding in the NOPR that current offer caps could also prevent the RTO/ISO from dispatching the most efficient set of resources because the RTO/ISO will not have access to the underlying costs associated with the multiple incremental energy offers above the offer cap. 34 34 CEA Comments at 2-3; EEI Comments at 3-4. 2. Comments That Oppose Reforming Current Offer Caps 20. Several commenters disagree with the Commission's finding that the current offer cap is unjust and unreasonable and therefore should be reformed. For example, CAISO argues that the current $1,000/MWh offer cap in CAISO should not be changed because $1,000/MWh is far in excess of what the highest reasonable cost-justified offer could be from a CAISO resource. 35 CAISO explains that natural gas prices have generally been stable, and argues that even if natural gas market fundamentals changed, periods when incremental energy costs exceed $1,000/MWh would be infrequent and short-lived and do not justify the offer cap changes proposed in the NOPR. 36 ISO-NE does not oppose raising its current offer cap to a higher fixed level, but nonetheless maintains that the current $1,000/MWh offer cap in ISO-NE is just and reasonable because the cap has not inappropriately limited LMPs below the marginal cost. 37 35 CAISO Comments at 4. 36 Id. at 4-5. 37 ISO-NE Comments at 1-3. 21. The ISO-NE and SPP Market Monitors assert that there is no need to reform the offer caps in their markets. The ISO-NE Market Monitor states that there is no need to revise ISO-NE's $1,000/MWh offer cap because natural gas prices have become more stable and, if completed, proposed pipeline expansions in New England will help alleviate some of the natural gas congestion that led to the high LMPs observed in ISO-NE in 2014. 38 The SPP Market Monitor states that SPP resources have not experienced costs above $1,000/MWh and the SPP Market Monitor expects that fuel price spikes that would raise costs to that level would rarely occur. 39 38 ISO-NE Market Monitor Comments at 12-14 (citing ISO-NE Market Rule 1, Appendix A, Section III.A.15). 39 SPP Market Monitor Comments at 8-9. 22. A number of commenters argue, for various reasons, that current RTO/ISO offer caps should not be revised. 40 For example, several commenters assert that revising the offer cap is an overreaction to anomalous, infrequent, and/or transitory market and weather conditions that do not justify changing the offer cap. Steel Producers' Alliance observes that the current offer cap has only been an issue in a handful of instances, which it argues demonstrates that the offer cap is set at the appropriate level and performing as intended. 41 APPA, NRECA, and AMP assert that the offer cap issues described in the NOPR are merely hypothetical, and that there is insufficient evidence that current offer caps are unjust and unreasonable. 42 40 See generally APPA, NRECA, and AMP Comments at 5-8; AF&PA Comments at 2-3; CAISO Comments at 2; Industrial Customers Comments at 3-9; Industrial Energy Consumers Comments at 2; ISO-NE Market Monitor Comments at 12-14; NY Department of State Comments at 3-5; NYPSC Comments at 1, 4; Steel Producers' Alliance Comments at 2-3; ODEC Comments at 3-5; PG&E Comments at 1-2; PJM Joint Consumer Advocates Comments at 2-4; SPP Market Monitor Comments at 2, 6, 12-13; TAPS Comments at 1, 4-7. 41 Steel Producers' Alliance Comments at 2. 42 APPA, NRECA, and AMP Comments at 9-13. 23. Some commenters disagree with the NOPR's preliminary finding that offer caps are unjust and unreasonable because they can suppress LMPs below the marginal cost of production. For example, ODEC argues that a higher cap is unnecessary because LMPs are lower in PJM than they were when PJM's current higher offer cap was adopted. 43 Other commenters argue that LMPs above $1,000/MWh do not send a useful price signal to consumers, 44 and may in fact harm consumers because most demand for electricity is inelastic, or unresponsive to price changes. 45 These commenters argue that, because most demand is inelastic, raising the offer cap would lead to market power abuses and transfer payments from load to generators. 46 For example, Industrial Customers argue that resources can take advantage of inelastic demand and exercise market power to obtain prices above competitive levels. 47 The New York Commission argues that without sufficient competition, including from demand response, raising the offer cap will not change behavior in NYISO and will only increase prices and burden ratepayers. 48 The New York Commission asserts that the Commission should not revise the offer cap until more effective demand response resources can participate in NYISO's real-time energy market. 49 43 ODEC Comments at 3-4. 44 NY Department of State Comments at 3; New York Commission Comments at 5-6. 45 AF&PA Comments at 2-3; Industrial Energy Consumers Comments at 2; Industrial Customers Comments at 10; PJM Joint Consumer Advocates Comments at 4; TAPS Comments at 6, 12. 46 Direct Energy Comments at 3-5; Industrial Customers Comments at 10; NY Department of State Comments at 3; TAPS Comments at 3. 47 Industrial Customers Comments at 10. 48 New York Commission Comments at 5-6. 49 New York Commission Comments at 6. 24. Many commenters argue that the current offer caps in RTOs/ISOs should be maintained because they protect consumers from excessive LMPs that result from market power abuse. 50 For example, NY Department of State argues that the offer cap benefits consumers by shielding customers from high real-time LMPs or market manipulation. 51 Similarly, TAPS states that the current offer caps act as a critical safety valve to protect consumers from excessive prices. 52 Industrial Customers assert that increasing the offer cap above $1,000/MWh would raise consumers' costs to hedge electricity procurements. 53 Industrial Energy Consumers stress that offer caps are essential for consumers to be confident that rate structures are fair and nondiscriminatory. 54 50 Industrial Customers Comments at 3, 10-11; Industrial Energy Consumers Comments at 2; TAPS Comments at 1, 8-12, NY Department of State Comments at 4. 51 NY Department of State Comments at 4. 52 TAPS Comments at 1. 53 Industrial Customers Comments at 20. 54 Industrial Energy Consumers Comments at 2. 25. Some commenters argue that current offer caps do not suppress LMPs in a manner that impacts resource investment decisions. AF&PA asserts that periodic and unpredictable price spikes have limited value in sustaining resource viability or inducing consumers to make long term behavioral changes. 55 Similarly, TAPS argues that allowing offers above $1,000/MWh to set the LMP would not have a practical impact on resource investment decisions because, even if the offer cap were raised, the LMP would remain the same in the vast majority of hours. TAPS adds that no resource owner would base its capital investments on the hope that LMPs will be extremely high for just a few hours every year. 56 55 AF&PA Comments at 2-3. 56 TAPS Comments at 6-7. 26. Some commenters argue that offer cap waivers are the best remedy to address issues associated with the offer cap. 57 For example, Industrial Energy Consumers state that the Commission adequately addressed the isolated Polar Vortex event by granting either temporary, limited waivers, or uplift payments, thereby sending the correct price signal for investment. 58 AF&PA supports current Commission protocols of waivers and other reforms that allow generators to recover verifiable costs in certain situations, and supports the expansion and streamlining of these protocols. 59 57 AF&PA Comments at 6-7; Industrial Energy Consumers Comments at 2; Steel Producers' Alliance Comments at 2-3. 58 Industrial Energy Consumers Comments at 2. 59 AF&PA Comments at 6. 3. Generally Applicable Offer Cap Reforms 27. In addition to the four preliminary findings stated above, 60 the Commission also stated in the NOPR that the lack of a uniform offer cap has the potential to exacerbate seams issues between neighboring RTOs/ISOs. 61 The Commission recognized in the NOPR that the proposed reforms could result in neighboring markets having different effective offer caps in a given interval because the marginal cost of production in one RTO/ISO may differ from neighboring markets due to resources with different short-run marginal costs being on the margin in those markets. 62 The Commission preliminarily found, however, that these differences will not adversely affect seams because the differences would be driven by actual costs and not by offer caps artificially suppressing LMPs. The Commission stated that, to the extent incremental energy offers can be verified, a reform applicable to all RTOs/ISOs that allows cost-based incremental energy offers to exceed $1,000/MWh would enhance market efficiency and mitigate the potential for seams issues. 63 The Commission sought comment on these preliminary findings and other seams issues related to this proposal. 60 See supra P 2. 61 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 70. 62 Id. P 71. 63 Id. P 48. 28. The majority of commenters agree with the NOPR's proposal to make a change in the offer cap across all RTOs/ISOs in order to avoid seams issues, 64 and several commenters generally agree with the importance of mitigating seams issues. 65 For example, the IRC notes the importance of uniformity in the treatment of offer caps, particularly in neighboring RTOs/ISOs. 66 NYISO supports a uniform RTO/ISO offer cap and argues that, in areas with a common fuel source, differing offer caps in neighboring regions could lead to restricted fuel procurement in the region with the lower offer cap. 67 MISO asserts that without a common offer cap, tight operating conditions could provide counterproductive arbitrage opportunities. 68 The ISO-NE Market Monitor notes that different offer caps in neighboring regions could be detrimental to ISO-NE's ongoing efforts to develop a clearing mechanism to select external resources in economic merit order. 69 64 See generally Dominion Comments at 8; Competitive Suppliers Comments at 23, 25; EEI Comments at 4; Exelon Comments at 22-23; MISO Comments at 19; NESCOE Comments at 2; PJM Power Providers Comments at 6-7; OMS Comments at 4; PJM/SPP Comments at 2-3; IRC Comments at 3; NY Department of State Comments at 6; NYISO Comments at 9-10; ISO-NE Market Monitor Comments at 14; Steel Producers' Alliance Comments at 3-4. Some of these commenters express conditional or qualified support of the NOPR and/or propose alternative offer caps. 65 Industrial Customers Comments at 21, 24; Midcontinent Joint Consumer Advocates Comments at 9-10; TAPS Comments at 21-22. 66 IRC Comments at 1, 3. 67 NYISO Comments at 10. 68 MISO Comments at 19. 69 ISO-NE Market Monitor Comments at 14. 29. The PJM Market Monitor states that the proposal's impact on seams would be consistent with efficient markets whereby energy would flow to where it is valued most. 70 EEI argues that the actual effect of the NOPR on seams would be determined by market forces and the marginal cost to operate the system. 71 70 PJM Market Monitor Comments at 12. 71 EEI Comments at 4. 30. With respect to the Western Electricity Coordinating Council (WECC), CAISO and Exelon argue that the Commission must address how it will ensure consistency between the proposed offer cap in CAISO and the existing $1,000/MWh offer cap in WECC. 72 CAISO and Exelon observe that, in instituting the existing offer cap in WECC, the Commission recognized the interdependency between CAISO and WECC and therefore stated that it would be unjust and unreasonable to have different offer caps in these two regions. 73 CAISO further asserts that for those RTOs/ISOs, such as CAISO, that do not share a seam with another RTO/ISO, the Final Rule should allow these RTOs/ISOs to demonstrate that raising the offer cap is unnecessary. 74 72 CAISO Comments at 14; Exelon Comments at 22. 73 CAISO Comments at 14 (citing Western Electric Coordinating Council, 133 FERC ¶ 61,026 (2010)); Exelon Comments at 22 (citing Western Electric Coordinating Council, 131 FERC ¶ 61,145 (2010)). 74 CAISO Comments at 2, 4. 31. Some market participants support the NOPR's applicability to all RTOs/ISOs in theory, but argue that the effect on seams would depend on implementation. The Delaware Commission cautions that the degree to which the verification of cost-based offers above $1,000/MWh is sufficiently rigorous will determine the effect on seams and that this will not be known until implementation. 75 ISO-NE agrees that consistent energy offer caps are important to prevent flows that run contrary to reliability needs, but argues that the NOPR's actual effect on seams is unknown because real-time cost verification for imports is not possible. 76 PJM Joint Consumer Advocates argue that the Commission's proposal could exacerbate seams because shortage pricing mechanisms vary across RTOs/ISOs. 77 Industrial Energy Consumers note that allowing different offer caps in adjacent markets could create seams issues. 78 75 Delaware Commission Comments at 14-15. 76 ISO-NE Comments at 9. 77 PJM Joint Consumer Advocates Comments at 6-7. 78 Industrial Energy Consumers Comments at 2. 32. Other commenters argue that there should be regional flexibility in implementing an offer cap. PG&E argues that a one-size-fits-all solution for all RTO/ISO markets is not appropriate. 79 As noted above, the NY Transmission Owners suggest that different hard caps in different regions might be justified, so long as regions that are dependent on the same gas supply coordinate their caps. 80 Direct Energy supports the NOPR's proposal for verified cost-based offers above $1,000/MWh, but argues that individual RTOs/ISOs should be able to set offer caps above $1,000/MWh in recognition of regional differences. 81 79 PG&E Comments at 1-2. 80 NY Transmission Owners Comments at 4-5. 81 Direct Energy Comments at 5-6. 33. APPA, NRECA, and AMP assert that the NOPR runs counter to the Commission's usual practice of recognizing and accommodating regional differences. 82 APPA, NRECA, and AMP state that a concern over seams is not adequate justification for the rule because it fails to account for regional differences, and because the Commission determined that the need for an increase in the offer cap outweighed seams issues when it approved PJM's $2,000/MWh offer cap. 83 82 APPA, NRECA, and AMP Comments at 5-6. 83 Id. at 6 (citing PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 55). Additionally, APPA, NRECA, and AMP argue that the fact that PJM has this higher offer cap and it has not resulted in seams issues proves that concerns over seams are purely hypothetical. Id. B. Determination 34. Based on our analysis of the record, we adopt the preliminary findings in the NOPR, and conclude that the offer caps currently in effect in RTOs/ISOs are unjust and unreasonable. We find that the currently effective offer caps may prevent a resource from recovering its short-run marginal costs, which could result in that resource operating at a loss. 84 We also find that the $1,000/MWh offer caps in effect in some RTOs/ISOs may suppress LMPs below the marginal cost of production given that recent history demonstrates that resource short-run marginal costs can exceed $1,000/MWh. 85 We also find that preventing resources from including all of their short-run marginal costs in their incremental energy offers when those costs exceed $1,000/MWh may discourage resources that are not subject to must-offer requirements from offering their supply to the RTO/ISO energy market. Finally, preventing resources from including their short-run marginal costs in their incremental energy offers when those costs exceed $1,000/MWh may also prevent the RTO/ISO from dispatching the most efficient resources when several resources have short-run marginal costs above $1,000/MWh. 84 As discussed above, the Commission has previously accepted temporary changes to tariff provisions in MISO that enabled resources to receive uplift for short-run marginal costs above the $1,000/MWh offer cap. However, cost recovery through uplift is only guaranteed if a resource experiences short-run marginal costs above $1,000/MWh during the time period for which the Commission has accepted tariff revisions related to the offer cap. See supra P 14. Currently, resources in many RTOs/ISOs do not have the opportunity to recover short-run marginal costs above $1,000/MWh without a tariff modification. 85 PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 6. 35. We disagree with commenters who argue that there is no need to reform the offer cap or that the problems described in the NOPR are hypothetical and that insufficient evidence exists to conclude that the current offer caps are unjust and unreasonable. As discussed in the NOPR, three RTOs/ISOs made filings with the Commission (two on multiple occasions) to address issues related to the level of the offer cap. 86 The waiver requests and high natural gas costs experienced during the Polar Vortex, which could have caused some resources to experience costs above $1,000/MWh, demonstrate that the deficiencies of current offer caps, in particular the $1,000/MWh offer cap, are concrete rather than hypothetical. 86 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 13-17. 36. Without Commission action to remedy these deficiencies, some resources could be forced to operate at a loss and some resources would be discouraged from offering their supply to the grid when it is most needed. A central tenet of sound wholesale electric market design is that resources must have an opportunity to recover their costs, so the question left to the Commission is how to provide that opportunity for cost recovery when short-run marginal costs exceed the $1,000/MWh offer cap. We have essentially two choices to enable resources to recover short-run marginal costs above $1,000/MWh: To allow cost recovery through energy prices or through uplift. Short-run marginal costs, which resources include in the incremental energy component of their supply offers, are typically used to calculate LMP. As noted above, 87 ensuring that LMPs reflect the marginal cost of production sends critical information to market participants, improves transparency, and generally results in more efficient outcomes in RTO/ISO energy markets. We find that recovery through energy prices, in most circumstances, will provide the additional benefit that LMPs reflect the marginal cost of production, will increase transparency about the functioning of RTO/ISO energy markets, and will facilitate efficient dispatch of resources with short-run marginal costs above $1,000/MWh. 88 While we recognize that offer caps may not bind frequently, the Federal Power Act requires the Commission to ensure that rates are just and reasonable. 87 See supra P 5. 88 We note that uplift is necessary in some circumstances. For example, resource start-up and no-load costs are not typically included in LMP, and some resources receive uplift to recover these costs. 37. We also disagree with commenters that LMPs above $1,000/MWh do not send useful price signals to market participants because, in fact, the Commission has found on prior occasions that LMPs based on short-run marginal cost send efficient short-run and long-run signals to the market. 89 In the short-run, LMPs based on short-run marginal costs are an effective way to communicate information to market participants about the cost of providing the next unit of energy. For example, when LMPs are high, they provide a signal to customers to reduce consumption and a signal to suppliers to increase production or to offer new supplies to the market. In the long-run, LMPs based on short-run marginal costs can help to inform investment decisions. 90 89 PJM Interconnection, L.L.C., 110 FERC ¶ 61,053, at P 114 (2005) (“offers [in a competitive market] should set the market clearing price in order to send appropriate price signals about the need for new generation or enhanced load response”). PJM 2014 Offer Cap Order II, 146 FERC ¶ 61,078 at P 40 (“By limiting legitimate, cost-based bids to no more than $1,000/MWh, the market produces artificially suppressed market prices and inefficient resource selection”). 90 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 7. 38. Furthermore, as noted by Competitive Suppliers and EEI, even if LMPs exceed $1,000/MWh for only a few hours during the year, the resulting LMPs in those hours could affect long-term price signals. 91 For all of these reasons, we conclude that the existing offer caps are not just and reasonable and, thus, need to be reformed. 91 Competitive Suppliers Comments at 9; EEI Comments at 5. 39. With respect to the applicability of the reforms adopted in this Final Rule, we find that making the reforms applicable to all RTOs/ISOs will avoid seams issues that could arise if RTOs/ISOs had different offer caps. 92 We find that these offer cap reforms will also result in more economically efficient flows between RTOs/ISOs because transactions across RTO/ISO seams will occur based on economic merit rather than based on differences in the offer cap. 93 92 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 70-71. 93 Id. P 74. 40. We also find that continued use of temporary waivers related to the offer cap, as advocated by some commenters, is an inappropriate remedy for problems associated with current offer caps in RTOs/ISOs. The reforms adopted in this Final Rule will provide more certainty to market participants and reduce the administrative burden on RTOs/ISOs associated with requests for temporary waivers of various tariff provisions related to the $1,000/MWh offer caps prior to the start of every winter to ensure that resources are given the opportunity to recover their costs. 94 We also find that problems identified with the current offer caps are better addressed through a rulemaking rather than through continued use of either ad hoc actions to approve tariff waivers or temporary changes to tariff provisions to remedy issues associated with existing RTO/ISO offer caps. 94 Id. PP 45, 49 (citing Notice Inviting Comments, Docket No. AD14-14-000 at 2). 41. We find that the reasons for requiring the proposed offer cap reforms apply equally to CAISO. As discussed above, the potential for resources to have short-run marginal costs above CAISO's current $1,000/MWh offer cap requires some action to ensure that resources have an opportunity to recover costs. As in other RTO/ISO markets, increasing the offer cap will improve price formation in CAISO at times when the short-run marginal costs of CAISO resources exceed $1,000/MWh. CAISO's lack of a seam with another RTO/ISO does not alter these effects. Contrary to the implication of CAISO's argument, as explained above, we are not relying on the avoidance of seams issues as the sole rationale for adopting this Final Rule. With respect to comments regarding the WECC offer cap, we find that this issue is unique to CAISO, and if CAISO finds that this Final Rule raises seams issues with WECC, it may raise such issues elsewhere. IV. Offer Cap Reforms 42. Having concluded that the existing offer caps are not just and reasonable, section 206 of the Federal Power Act requires that the Commission determine the practices that are just and reasonable. 95 We direct each RTO/ISO to establish in their tariffs the following three requirements: 95 16 U.S.C. 824e (2012). (1) A resource's incremental energy offer must be capped at the higher of $1,000/MWh or that resource's cost-based incremental energy offer. For the purpose of calculating Locational Marginal Prices, Regional Transmission Organizations and Independent System Operators must cap cost-based incremental energy offers at $2,000/MWh. (Offer cap structure requirement) (2) The costs underlying a resource's cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used for purposes of calculating Locational Marginal Prices. If a resource submits an incremental energy offer above $1,000/MWh and the costs underlying that offer cannot be verified before the market clearing process begins, that offer may not be used to calculate Locational Marginal Prices and the resource would be eligible for a make-whole payment if that resource is dispatched and the resource's costs are verified after-the-fact. A resource would also be eligible for a make-whole payment if it is dispatched and its verified cost-based incremental energy offer exceeds $2,000/MWh. (Verification requirement) (3) All resources, regardless of type, are eligible to submit cost-based incremental energy offers in excess of $1,000/MWh. (Resource neutrality requirement) 43. The offer cap structure requirement is discussed in section IV.A. The verification requirement is discussed in section IV.B. The resource neutrality requirement is discussed in section IV.C. A. Offer Cap Structure 1. NOPR Proposal 44. In the NOPR, the Commission proposed the following offer cap structure requirement: A resource's incremental energy offer used for purposes of calculating Locational Marginal Prices in energy markets must be capped at the higher of $1,000/MWh or that resource's cost-based incremental energy offer. 96 96 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 53. The Commission sought comments on this proposed offer cap structure requirement and whether a hard cap that limited the incremental energy offers used to calculate LMPs would be necessary. The Commission also sought comment on whether the level of the hard cap should be $2,000/MWh or another value. 97 97 See id. P 55. 2. Comments 45. Comments about the proposed offer cap structure focus on two key areas: (1) Whether incremental energy above $1,000/MWh should be cost-based; and (2) how LMPs should be calculated when resource short-run marginal costs exceed $1,000/MWh, including whether resources with costs above $1,000/MWh should be compensated through higher LMPs or through uplift, whether a hard cap is necessary, and the appropriate level of any hard cap. . a. Whether Incremental Energy Offers Above $1,000/MWh Should be Cost Based 46. Commenters differed on the proposal to limit incremental energy offers above $1,000/MWh to cost-based incremental energy offers. Some commenters support this proposal and argue that it is appropriate to limit incremental energy offers that are not cost-based to $1,000/MWh as a backstop mitigation measure. 98 As discussed further below, 99 many commenters support the verification requirement proposed in the NOPR and stress that incremental energy offers above $1,000/MWh must be cost-based incremental energy offers before such offers are eligible to calculate LMPs. 100 98 MISO Comments at 7; NY Transmission Owners Comments at 2-3. 99 See infra PP 100-101. 100 See generally NYISO Comments at 2; SCE Comments at 1-2; PG&E Comments at 3; NY Transmission Owners Comments at 3; Golden Spread Comments at 3; Delaware Commission Comments at 11; TAPS Comments at 12; NESCOE Comments at 3. 47. Regarding offer caps in general, MISO states that the offer cap is currently necessary because demand in RTO/ISO energy and ancillary service markets is inelastic and also because they serve as a safety net. 101 MISO adds that offer caps should be set high enough so as not to interfere with valid market dynamics. 102 NY Transmission Owners maintain that the $1,000/MWh offer cap is an important backstop to protect consumers from the exercise of market power should mitigation fail. 103 101 MISO Comments at 7. 102 Id. at 7. 103 NY Transmission Owners Comments at 2-3. 48. Some commenters argue that the $1,000/MWh threshold, above which a resource's incremental energy offer submitted to the RTO/ISO must be cost-based, is too high. The Delaware and New Jersey Commissions recommend that in PJM, all incremental energy offers above $400/MWh be verified before such offers are eligible to set LMP, 104 and the Pennsylvania Commission asks the Commission to carefully consider the threshold above which incremental energy offers are verified. 105 The PJM Market Monitor states that there is no reason that $1,000/MWh should be the dividing line between incremental energy offers that can include markups and incremental energy offers that must be cost-based, and that the threshold could be lowered to $500/MWh in PJM noting that only 0.17 percent of all offers were above $400/MWh in 2015. 106 104 Delaware Commission Comments at 4-7; New Jersey Commission Comments at 9. 105 Pennsylvania Commission Comments at 10-13. 106 PJM Market Monitor Comments at 2. 49. Exelon states that while it supports removing the offer cap completely, if the Commission finds that incremental energy offers above a certain threshold must be cost-based, 107 Exelon recommends a $2,000/MWh threshold which it states is above a recent fully supported cost-based incremental energy offer of $1,724/MWh seen in PJM in 2014. 108 Exelon also recommends that this threshold be reevaluated on a triennial basis to ensure it reflects market realities. 109 107 Exelon refers to this threshold as a “market-based offer cap.” See, e.g., Exelon Comments at 1, 7-10. 108 Exelon Comments at 9-10. 109 Id. at 10. 50. Other commenters support an absolute cap on the incremental energy offers, even if a resource's short-run marginal costs exceed that cap. 110 Industrial Customers also claim that if incremental energy offers above $1,000/MWh are permitted, resources would have no incentive to minimize their fuel costs because they would recover all of their costs if they were dispatched by the RTO/ISO. 111 Potomac Economics states that resources should be prohibited from submitting incremental energy offers above $2,000/MWh, and claims that without such an absolute cap, natural gas prices could be bid up to extraordinary levels. 112 110 Industrial Customers Comments at 10; Potomac Economics Comments at 7. 111 Industrial Customers Comments at 19. 112 Potomac Economics Comments at 7. Potomac Economics is the external independent market monitor for NYISO, MISO, and ISO-NE. ISO-NE and NYISO also have internal Market Monitoring Units. 51. However, several commenters state that resources should be able to submit incremental energy offers that reflect their short-run marginal costs, even if those offers exceed $1,000/MWh. 113 For example, CEA argues that it is prudent to modify current offer caps to allow resources to submit incremental energy offers above $1,000/MWh when fuel and other inputs cause the marginal cost of production to exceed $1,000/MWh. 114 PJM Power Providers argue that raising the offer cap is important because it would allow energy clearing prices to reflect market conditions and provide stability to consumers and suppliers by eliminating the need for ad hoc waivers. 115 113 See generally Competitive Suppliers Comments at 12-14; Dominion Comments at 3-4; EEI Comments at 3-4; Golden Spread Comments at 1; MISO Comments at 6; NY Transmission Owners Comments at 3; OMS Comments at 3; PJM/SPP Comments at 6; PJM Market Monitor Comments at 1; Six Cities Comments at 2. 114 CEA Comments at 3-4. 115 PJM Power Providers Comments at 1-2 (citing NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 14, 16, 17). 52. Some commenters argue that offer caps that limit the incremental energy offers that resources can submit should be increased 116 or removed entirely. 117 For example, API and the Texas Commission argue that the offer cap should be raised significantly. 118 The Texas Commission asserts that MISO's offer cap should be raised significantly to provide greater assurance of resource adequacy, reduce administrative complexity, and minimize uplift charges. 119 116 API Comments at 3, 8, 13; Exelon Comments at 7; OMS Comments (on behalf of Public Utility Commission of Texas (Texas Commission), referring to MISO's $1,000/MWh offer cap) at 3 n. 7; NEI Comments at 2, 4-5. 117 NEI Comments at 2, 4-5; Competitive Suppliers Comments at 4-5, 7, 13-15; Exelon Comments at 9-10. 118 API Comments at 3, 8, 13; OMS Comments (on behalf of Texas Commission) at 3 n.7. 119 OMS Comments (on behalf of Texas Commission) at 3 n.7. 53. MISO states that it does not oppose the NOPR proposal to revise the offer cap because the proposal will allow market clearing prices to more accurately reflect the true marginal cost of production while protecting consumers from the effects of manipulation and improving price transparency, and the proposal should also reduce uplift payments. 120 However, MISO urges the Commission to consider whether the offer cap proposal in the NOPR is an appropriate long-term approach and states that it could support a gradual relaxation of offer caps to allow market forces to respond accordingly. 121 120 MISO Comments at 6. 121 Id. at 7. 54. PJM Power Providers assert that resources should be able to submit cost-based incremental energy offers that reflect all short-run marginal costs. 122 Competitive Suppliers and Exelon argue that the offer cap should be removed entirely, or raised to avoid adverse impacts on the market. 123 According to Competitive Suppliers, significant improvements in electricity markets and market monitoring have occurred since the $1,000/MWh offer cap was put in place nearly 20 years ago. 124 Competitive Suppliers also argue that, given these improvements, the offer cap should be removed, or if that approach is not taken, the verification process should involve minimal distortions. 125 122 PJM Power Providers Comments at 2. 123 Competitive Suppliers Comments at 4-5, 8, 14; Exelon Comments at 10. 124 Competitive Suppliers Comments at 8, 14-15. 125 Id. at 4-5. b. How LMPs Should Be Calculated When Resource Short-Run Marginal Costs Exceed $1,000/MWh 55. Several commenters discuss how LMPs should be calculated when resource short-run marginal costs exceed $1,000/MWh, with some commenters arguing that LMPs should rise to reflect the marginal cost of production and others arguing that resources with short-run marginal costs above $1,000/MWh should be compensated outside of the market through uplift rather than through higher LMPs. Commenters also discuss the need for a hard cap and the appropriate level for any hard cap. i. Whether To Compensate Resources With Costs Above $1,000/MWh Through Uplift or Higher LMPs 56. As noted above, 126 several commenters state that incremental energy offers above $1,000/MWh should be used to calculate LMPs because the resulting LMPs will better reflect the marginal costs of production. 127 MISO states that permitting cost-based incremental energy offers above $1,000/MWh to set LMPs should improve price transparency and should reduce uplift payments. 128 EEI states that competitive wholesale electricity markets should provide accurate price signals and that cost-based incremental energy offers above $1,000/MWh should be used to calculate LMPs because LMPs should reflect the marginal cost of operating the system, which will promote efficient operation, resource accuracy, and result in savings for consumers. 129 126 See supra P 17. 127 CEA Comments at 3-4; Competitive Suppliers Comments at 9-13; EEI Comments at 3; Exelon Comments at 5-7; Powerex Comments at 6; PJM Providers Group Comments at 2; Golden Spread Comments at 1; MISO Comments at 6; PJM/SPP Comments at 1-2. 128 MISO Comments at 6. 129 EEI Comments at 3-4. 57. However, other commenters argue that incremental energy offers above $1,000/MWh, even if they are cost-based, should not be able to set LMP. 130 For example, Industrial Customers argue that letting incremental energy offers set LMP would be a windfall to resources. 131 Many commenters argue that uplift or temporary waivers should be used to account for instances when resources' short-run marginal costs exceed the offer cap. Some commenters argue that rather than letting incremental energy offers above $1,000/MWh set LMP, resources with costs above the $1,000/MWh offer cap should be compensated through uplift. 132 For example, the New York Commission argues that an uplift mechanism could ensure that generators can recover all short-run marginal costs. 133 KEPCo/NCEMC asserts that if cost-based incremental energy offers above $1,000/MWh are based on inaccurate fuel cost estimates, there may be no means of remedying the effects on the markets. 134 KEPCo/NCEMC add that uplift is a more cost effective way to ensure both resource cost recovery and just and reasonable prices. 135 Industrial Customers assert that uplift is preferable to using incremental energy offers above $1,000/MWh to calculate LMP because uplift payments ensure cost recovery and can be limited to the resources that are necessary to balance supply and demand, rather than compensating all resources. 136 130 APPA, NRECA, and AMP Comments at 8-10; Industrial Customers Comments at 9; NY Department of State Comments at 3; ODEC Comments at 3; PJM Joint Consumer Advocates Comments at 5; TAPS Comments at 5-6; Steel Producers' Alliance Comments at 3. 131 Industrial Customers Comments at 9. 132 APPA, NRECA, and AMP Comments at 8, 13-14, 16; Industrial Customers Comments at 8-9, 23-24; KEPCo/NCEMC Comments at 4; TAPS Comments at 5-6; New York Commission Comments at 6-7; SPP Market Monitor Comments at 2, 4, 6-7; Industrial Energy Consumers Comments at 2. 133 New York Commission Comments at 6-7. 134 KEPCo/NCEMC Comments at 4. 135 Id. at 4. 136 Industrial Customers Comments at 8-9. ii. Whether To Adopt a Hard Cap 58. Comments differ on the need for a hard cap that would limit the incremental energy offers RTOs/ISOs use to calculate LMPs, a limit referred to herein as a hard cap. Many commenters support a hard cap, 137 and some argue that a hard cap serves as an important backstop mitigation measure to address concerns about the competitiveness of natural gas markets or as a means to protect consumers from unreasonably high LMPs. 138 137 ISO-NE Comments at 3; ISO-NE Market Monitor Comments at 12; Joseph Margolies Comments at 8; NYISO Comments at 7; SPP Market Monitor Comments at 2, 13; TAPS Comments at 7. 138 Direct Energy Comments at 3-5; Industrial Customers Comments at 12; ISO-NE Comments at 3; Joseph Margolies Comments at 3; Potomac Economics Comments at 7; NY Department of State Comments at 3; TAPS Comments at 7. 59. CAISO, ISO-NE, and NYISO support a hard cap. CAISO asserts that, assuming it were able to verify cost-based offers above $1,000/MWh, a hard cap is necessary if the Commission permits resources to submit incremental energy offers above $1,000/MWh. 139 CAISO adds that a hard cap may help mitigate price spikes in fuel markets. 140 ISO-NE supports a hard cap established at a fixed level and argues that any new offer cap should be imposed in a straightforward manner such that market participants know the level of the offer cap with certainty when making advance fuel supply arrangements. 141 NYISO asserts that a hard cap will protect the market from the inadvertent submission of offers above the cap, create bounds for offers that are difficult to verify, and prevent potential attempts to exercise market power that are not otherwise addressed by existing mitigation rules. 142 While MISO takes no position on a hard cap as discussed further below, 143 MISO states that a hard cap is easier to integrate with other market design elements because it is more challenging to establish the appropriate levels for other market elements, such as MISO's Operating Reserve and Transmission Constraint demand curves, without a hard cap because the maximum incremental energy offers would not be limited to a pre-defined value. 144 139 CAISO Comments at 10. As noted in P 20, supra, CAISO opposes raising CAISO's current $1,000/MWh offer cap. 140 Id. at 10. CAISO refers to the hard cap as a “secondary hard cap.” 141 ISO-NE Comments at 2-3. 142 NYISO Comments at 8. 143 See infra P 69. 144 MISO Comments at 13. 60. Potomac Economics, and the ISO-NE and PJM market monitors stress the need for the hard cap to address concerns about uncompetitive conditions in natural gas markets when natural gas supplies are scarce. 145 Potomac Economics contends that during natural gas shortages, natural gas markets have two dominant customer types: Local gas distribution companies and natural gas generators. 146 Potomac Economics states that natural gas generators are frequently the marginal buyers since local gas distribution companies will not interrupt supply to their customers at any price. Potomac Economics asserts that without a hard cap, natural gas prices could be bid up to extraordinary levels because local distribution companies are guaranteed to recover their cost, regardless of how high. 147 The PJM Market Monitor also states that vertically-integrated utilities with a gas marketing function could have the incentive to exercise market power in natural gas markets during extreme conditions in an effort to exercise market power in electricity markets. 148 145 ISO-NE Market Monitor Comments at 13-14; Potomac Economics Comments at 7; PJM Market Monitor Comments at 4. 146 Potomac Economics Comments at 7. 147 Id. 148 PJM Market Monitor Comments at 4. 61. The ISO-NE Market Monitor also asserts that natural gas markets lack structural measures to prevent the exercise of market power. According to the ISO-NE Market Monitor, the offer cap in electricity markets can impact prices in natural gas markets when natural gas supplies are scarce because natural gas resources, particularly resources with must-offer requirements, are the marginal customers in natural gas markets and thus have a significant impact on natural gas prices. 149 149 ISO-NE Market Monitor Comments at 13-14. 62. Although the PJM Market Monitor argues that, in the absence of market power, there should be no absolute cap on the short-run marginal costs reflected in an incremental energy offer, 150 the PJM Market Monitor opines that the removal of hard caps in electricity markets should be considered in light of the competitiveness of natural gas markets. The PJM Market Monitor asserts that it is essential that market participants have confidence in the competitiveness of natural gas markets before removing hard caps in electricity markets. 151 150 PJM Market Monitor Comments at 1. 151 Id. at 4. 63. The ISO-NE, PJM, and SPP market monitors also explain that when natural gas supplies are scarce, open exchanges for natural gas, such as the Intercontinental Exchange (ICE), tend to have low liquidity and wide bid-ask spreads. These market monitors state that it can be difficult to verify the short-run marginal cost of natural gas resources during periods when open natural gas exchanges have low liquidity because natural gas resources may purchase natural gas bilaterally rather than through the exchanges, and therefore the bid and ask spreads and settled transactions observed on the open exchanges may not represent the costs of the natural gas resources that make bilateral natural gas purchases. Furthermore, when liquidity in the open exchanges is low and the bid-ask spreads are wide, the ISO-NE, PJM, and SPP market monitors explain that there may be little basis on which to verify a resource's natural gas procurement costs. 152 152 ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6; SPP Market Monitor Comments at 7. 64. The New Jersey Commission and NY Transmission Owners also argue that a hard cap is necessary to address issues related to the interactions between the gas and electricity markets. 153 NY Transmission Owners explains that resource owners with costs above $1,000/MWh that also own infra-marginal resources may benefit from paying more for natural gas which in turn increases LMPs and thus the revenues that infra-marginal resources receive. 154 NY Transmission Owners further states that it will be difficult for market monitors to ascertain whether the price a resource has paid for natural gas reflects its expectations about the electricity market or an attempt to impact LMPs, and suggests that a hard cap can address these issues. 155 The New Jersey Commission similarly states that, absent a hard cap, market power in natural gas markets could drive up cost-based incremental energy offers in electricity markets and increase LMPs. 156 153 NY Transmission Owners Comments at 3-4; New Jersey Commission Comments at 9. 154 NY Transmission Owners Comments at 4. 155 Id. 156 New Jersey Commission Comments at 9. 65. The SPP Market Monitor states that it would prefer to maintain SPP's existing $1,000/MWh offer cap, but if it is to be revised, it would prefer a new fixed hard cap to serve as a backstop market power mitigation measure during periods of market anomalies when existing measures may fail to protect consumers. 157 157 SPP Market Monitor Comments at 6, 13. 66. Comments from other stakeholders generally support a hard cap to protect customers against market power abuse. 158 For example, the Ohio Commission asserts that if the Commission does not require PJM and the PJM Market Monitor to jointly review these cost-based energy offers, the $2,000/MWh hard cap in PJM should remain to protect against market power concerns and unverified price increases. 159 Industrial Customers argue that the offer cap works in tandem with market power mitigation measures to prevent excessive prices when supplies are tight given that demand is inelastic. 160 158 See generally Direct Energy Comments at 4-5; Ohio Commission Comments at 6-7; Industrial Customers Comments at 10-11; TAPS Comments at 8-10; New Jersey Commission Comments at 7. 159 Ohio Commission Comments at 6-7. 160 Industrial Customers Comments at 10-11. 67. Some commenters argue that a hard cap is necessary to protect customers from unjust and unreasonable prices resulting from market aberrations or other events when RTOs/ISOs fail to function properly. 161 For example, TAPS asserts that removing the offer cap entirely would result in the Commission failing to meet its statutory duty to protect against excessive prices, 162 and it argues that the hard cap provides crucial damage control to shield consumers from unreasonably high prices. 163 Industrial Customers argue that the hard cap helps discipline generator fuel procurement costs, stating that full cost recovery would significantly reduce incentives for generators to minimize their costs if these costs can be passed on to consumers. 164 161 TAPS Comments at 8-9; Industrial Customers Comments at 19-20. 162 TAPS Comments at 10 (citing FERC v. Elec. Power Supply Ass'n, 136 S. Ct. 760, 764 (2016)). 163 Id. at 9-10. 164 Industrial Customers Comments at 19-20. 68. Commenters opposed to the inclusion of a hard cap on offers used to calculate LMPs generally argue that any cap would artificially suppress LMPs and increase uplift payments. 165 PJM/SPP state that there should not be a hard cap on cost-based offers used to calculate LMPs provided that appropriate verification processes are in place to ensure cost-based incremental offers reflect legitimate costs. 166 PJM/SPP also assert that a hard cap can create unhedgeable uplift payments. 167 PJM Power Providers assert that resources should be able to submit cost-based incremental energy offers that reflect their short-run marginal costs and that those offers should be able to set the LMP. 168 165 Competitive Suppliers Comments at 12-15; Dominion Comments at 4; Exelon Comments at 21-22; Golden Spread Comments at 2; PJM/SPP Comments at 6; EEI Comments at 7. 166 PJM/SPP Comments at 6. 167 Id. 168 PJM Power Providers Comments at 2. 69. MISO states that it does not have a strong preference on the imposition of a hard cap and notes that the same benefits and drawbacks that exist for the current $1,000/MWh hard cap (in some markets) would apply to any new hard cap. 169 MISO identifies two drawbacks of a hard cap: (1) A hard cap could suppress LMPs below the marginal cost of production; and (2) a special uplift mechanism would be needed for offers that exceed the hard cap. 170 MISO states that a hard cap may not be necessary because the verification requirement safeguards the market and states that the limitations and implementation costs associated with a hard cap would likely overshadow the benefits. 171 169 MISO Comments at 13. 170 Id. 171 MISO Comments at 13. 70. Exelon and EEI oppose a hard cap, arguing that it is important for LMPs to be as consistent as possible with the marginal cost of operating the system and that, therefore, resources should always be permitted to offer their costs, and that such offers should always be eligible to set LMP. 172 As noted above, Competitive Suppliers assert that the offer cap should be removed entirely. 173 172 Exelon Comments at 21; EEI Comments at 4. 173 Competitive Suppliers Comments at 13. 71. Additionally, some commenters opposed to a hard cap assert that existing market monitoring and mitigation measures, as well as the proposed verification requirement for cost-based incremental energy offers above $1,000/MWh, render a hard cap unnecessary and duplicative. 174 For example, Dominion states that a hard cap is not necessary for cost-based incremental energy offers because market power concerns are not relevant for cost-based incremental energy offers as offers based on resource costs do not constitute an exercise of market power. 175 174 Competitive Suppliers Comments at 14; PJM/SPP Comments at 6; Dominion Comments at 4. 175 Dominion Comments at 4. 72. Commenters disagree about the appropriate level for any new hard cap. ISO-NE states that it does not have evidence to substantiate a specific recommendation for the level of any new hard cap. 176 NYISO states that the Commission should hold a technical workshop to determine the appropriate level of the hard cap that analyzes the elasticity of the fuel markets, including natural gas markets, and fuel prices at various demand levels. 177 176 ISO-NE Comments at 3. 177 NYISO Comments at 8. 73. Potomac Economics states that the $2,000/MWh level approved in PJM would be a reasonable hard cap for all RTOs/ISOs in the Eastern Interconnect. 178 However, Potomac Economics states that the Commission should adopt a $2,000/MWh cap that not only caps the incremental energy offers eligible to set LMP but also prevents resources from recovering incremental energy costs above $2,000/MWh. 179 Potomac Economics adds that the loss of generation resulting from any natural gas resources that do not procure natural gas during natural gas shortages due to such a cap will not substantially increase the probability of an electric outage. 180 178 Potomac Economics Comments at 7-8. 179 Id. at 8. Potomac Economics notes that its recommendation would require modifying PJM's current offer cap, which permits resources to recover costs above PJM's $2,000/MWh hard cap. 180 Id. 74. TAPS argues that offers above $1,500/MWh should not be used to calculate LMPs because a MISO analysis indicated that natural gas resources in MISO would have a marginal cost below $1,138/MWh if natural gas prices reached $65/MMBtu and that more than 98 percent of MISO's gas capacity would have a marginal cost below $1,500/MWh if gas prices reached $100/MMBtu. 181 TAPS further argues that $2,000/MWh is too high and that the value was not supported by PJM other than as a compromise between PJM stakeholders. 182 Midcontinent Joint Consumer Advocates argue that a $2,000/MWh hard cap is unreasonably high and could cause prices to rise up to $2,000/MWh. 183 181 TAPS Comments at 10-11. TAPS uses the phrase “hard offer cap,” which could indicate that RTOs/ISOs should limit offers to $1,500/MWh for purposes of calculating LMPs or that resources should not be able to submit incremental energy offers above $1,500/MWh. 182 Id. at 11. 183 Midcontinent Joint Consumer Advocates Comments at 4. 75. As noted above, some commenters support a $1,000/MWh hard cap on the incremental energy offers that are used to calculate LMPs. 184 For example, APPA, NRECA, and AMP assert that the hard cap should be set to $1,000/MWh in all RTOs/ISOs, including PJM, which currently has a $2,000/MWh hard cap. 185 Direct Energy and NY Transmission Owners state that different hard caps across RTOs/ISOs may be justified given differences in regional natural gas prices, but add that RTOs/ISOs with the same natural gas supply should have the same hard cap. 186 Additionally, APPA, NRECA, and AMP, ODEC, PJM Joint Consumer Advocates, and Steel Producers' Alliance all ask the Commission to reinstate PJM's previous $1,000/MWh offer cap. 187 ODEC and PJM Joint Consumer Advocates state that although they supported the consensus position on PJM's current $2,000/MWh offer cap as an interim measure, they state that they were awaiting Commission action on offer caps and do not support such a cap as a long-term policy. 188 ODEC and PJM Joint Consumer Advocates argue that the $2,000/MWh offer cap on cost-based offers is no longer necessary and that a $1,000/MWh offer cap is more appropriate because new measures, such as PJM's new capacity construct and additional measures implemented in response to the Polar Vortex, will ensure that prices remain at reasonable levels. 189 184 New Jersey Commission Comments at 8-9; TAPS Comments at 10-11; APPA, NRECA, and AMP Comments at 8-9. 185 APPA, NRECA, and AMP Comments at 9. 186 Direct Energy Comments at 3-4; NY Transmission Owners Comments at 5. 187 APPA, NRECA, and AMP Comments at 7; ODEC Comments at 3-5; PJM Joint Consumer Advocates Comments at 2-4; Steel Producers' Alliance Comments at 5. 188 ODEC Comments at 3; PJM Joint Consumer Advocates Comments at 2. 189 ODEC Comments at 5; PJM Joint Consumer Advocates Comments at 2-3. 76. Dominion states that the NOPR proposal will result in more accurate price signals and a better understanding of the true costs of serving demand, reduce uplift during stressed periods, and allow customers to more effectively hedge the costs of reliability through market participation. 190 NESCOE states that the offer cap reforms proposed in the NOPR appear to appropriately balance price formation issues, seams issues, and the potential for market power abuse while allowing for regional variation in implementing consumer protection mechanisms. 191 190 Dominion Comments at 3. 191 NESCOE Comments at 2. 3. Determination 77. The Commission is adopting aspects of the offer cap structure set forth in the NOPR, which caps a resource's incremental energy offer used for purposes of calculating LMPs in day-ahead and real-time energy markets at the higher of $1,000/MWh or that resource's cost-based incremental energy offer. Based on the comments received in this proceeding, the Commission is also adopting a hard cap as part of this Final Rule. 192 Although a resource may submit a cost-based incremental energy offer above $2,000/MWh, the hard cap will prohibit the use of such offers above $2,000/MWh when calculating LMPs. As discussed further in section IV.B below, incremental energy offers above $1,000/MWh must be verified before they are used to calculate LMPs. As noted above, RTOs/ISOs must cap verified cost-based incremental energy offers at $2,000/MWh when calculating LMPs. 192 The hard cap was not included in the proposal set forth in the NOPR, but the Commission sought comment on it. See NOPR, FERC Stats. & Regs. ¶ 32,714 at P 55. 78. As a result of this Final Rule, an RTO/ISO will treat resources' incremental energy offers differently, depending on the level of the offer itself. Each RTO/ISO shall treat incremental energy offers below $1,000/MWh as it currently does. Such offers: (1) Are subject to existing RTO/ISO market power mitigation procedures and are not required to be cost-based; and (2) may be used to calculate LMPs. A resource may only submit an incremental energy offer equal to or above $1,000/MWh if the offer is cost-based, that is, if the offer accurately reflects that resource's actual or expected short-run marginal costs. For an incremental energy offer equal to or above $1,000/MWh and less than or equal to $2,000/MWh, the RTO/ISO or Market Monitoring Unit must verify that the offer is cost-based before the RTO/ISO may use the offer to calculate LMPs. For an incremental energy offer above $2,000/MWh, the RTO/ISO or Market Monitoring Unit must also verify that the offer is cost-based. Cost-based incremental energy offers in excess of $2,000/MWh will be capped at $2,000/MWh for purposes of calculating LMPs. As such, the $2,000/MWh hard cap places an upper limit on the incremental energy offers that the RTO/ISO can use to calculate LMPs. 193 We note that the resulting LMPs may exceed $2,000/MWh due to losses and congestion. Additionally, resources with verified cost-based incremental energy offers above $2,000/MWh will be eligible to receive uplift. 193 The $2,000/MWh hard cap requires that the cost-based incremental energy offers that RTOs/ISOs may use to calculate LMPs may not exceed $2,000/MWh. 79. After consideration of the record in this proceeding, including responses to the question we asked about the need for a hard cap, we adopt a modified version of the offer cap structure proposed in the NOPR. This modified version recognizes the practical issues raised by commenters. While a hard cap may diminish the ability to fully address the shortcomings of the current offer caps identified above 194 in all circumstances, we find that, on balance, a hard cap is necessary to reasonably limit the adverse impact that imperfect information about a resource's short-run marginal costs during the verification process could have on LMPs. 194 See supra P 2. 80. First, the offer cap structure will reduce the likelihood that the $1,000/MWh offer cap in effect in some RTOs/ISOs 195 will suppress LMPs below the marginal cost of production. Ideally, LMPs in RTO/ISO energy markets should reflect the short-run marginal cost of the marginal resource. Under the offer cap structure adopted in this Final Rule, cost-based incremental energy offers up to $2,000/MWh that have been verified by either the RTO/ISO or Market Monitoring Unit as being a reasonable reflection of a resource's actual or expected short-run marginal cost may be used to calculate LMPs. 195 Specifically CAISO, ISO-NE, MISO, NYISO, and SPP. 81. Second, the offer cap structure and associated uplift payments discussed further in section IV.B below give resources the opportunity to be compensated for the short-run marginal costs they incur to provide service, which achieves the price formation goal of ensuring that resources have an opportunity to recover their costs. 82. Third, the offer cap structure adopted in this Final Rule will encourage a resource to offer supply to the market when it is needed most. A resource that is compensated for its costs has an incentive to offer its supply into the market even when those costs are high, which often occurs when supplies are tight. Fourth, the offer cap structure enables RTOs/ISOs to dispatch the most efficient set of resources when resources' short-run marginal costs exceed $1,000/MWh. 83. We also find that the offer cap structure will mitigate market power associated with incremental energy offers above $1,000/MWh, as some commenters suggest. The requirement that incremental energy offers above $1,000/MWh be cost-based retains the backstop mitigation function that current offer caps play in existing RTO/ISO market power mitigation because incremental energy offers that are not cost-based may not exceed $1,000/MWh. A cost-based incremental energy offer is based on the associated resource's short-run marginal cost, which constitutes a competitive offer free from the exercise of market-power. 84. Revising the offer cap to permit cost-based incremental energy offers up to $2,000/MWh to set LMP will reduce the likelihood that the offer cap will suppress LMPs below the marginal cost of production. Permitting cost-based incremental energy offers up to $2,000/MWh to set LMP will also reduce uplift associated with the current offer caps, which will be beneficial to the market because uplift payments are less transparent to market participants than LMPs that reflect the marginal cost of production. Therefore, we disagree with arguments that all resources with short-run marginal costs above $1,000/MWh should be compensated through uplift rather than through the LMP. As discussed further below, we adopt a hard cap and provide cost recovery for resources with short-run marginal costs above $2,000/MWh to address practical concerns raised about the offer verification process. As discussed further below, some resources may not know their actual short-run marginal costs at the time they submit cost-based incremental energy offers. 196 Accordingly, the RTO/ISO or Market Monitoring Unit will have to verify that such offers reasonably reflect the associated resource's expected short-run marginal costs, which necessarily involves an estimate. Furthermore, the information that RTOs/ISOs and/or Market Monitoring Units have to estimate and/or verify the short-run marginal costs of some resources may be imperfect. For example, as noted above, information about the short-run fuel costs of certain natural gas-fired resources may be limited when natural gas supplies are scarce because publicly available natural gas indices may not be representative of the price that such resources actually pay for fuel. 197 Given these limitations, we find it is appropriate to include a hard cap to ensure that LMPs calculated based on verified cost-based incremental energy offers above $1,000/MWh are just and reasonable. 196 See infra PP 105-108. 197 See supra P 63. 85. We disagree with Industrial Customers that resources would have no incentive to minimize their fuel costs if the offer cap is above $1,000/MWh because, in the absence of market power, resources have an incentive to compete with other resources in order to clear the RTO/ISO day-ahead and real-time energy markets. Any resource that is able to procure natural gas at a cost less than the cost that sets the LMP will earn a profit and thus has a strong incentive to manage its fuel procurement. 86. However, as part of the offer cap structure, we will require a hard cap of $2,000/MWh on offers that are used to calculate LMPs. Under the hard cap, an RTO/ISO must place an upper limit, or hard cap, on the cost-based incremental energy offers that it uses to calculate LMPs. 198 To implement the hard cap, we modify the offer cap structure requirement proposed in the NOPR and adopt the following offer cap structure requirement: 198 We note that PJM currently permits resources to submit cost-based incremental energy offers above its current $2,000/MWh hard cap, and PJM may use such offers to dispatch resources. However, incremental energy offers are capped at $2,000/MWh for purposes of calculating LMPs. See PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289. A resource's incremental energy offer must be capped at the higher of $1,000/MWh or that resource's cost-based incremental energy offer. For the purpose of calculating Locational Marginal Prices, Regional Transmission Organizations and Independent System Operators must cap cost-based incremental energy offers at $2,000/MWh. 87. We find that a hard cap is necessary for two primary reasons. First, a hard cap will address the fact that RTOs/ISOs and/or Market Monitoring Units may have imperfect information about resources' short-run marginal costs during the verification process. As discussed further in section IV.B below, several commenters note that there may be imperfect information associated with the verification of cost-based incremental energy offers above $1,000/MWh prior to the market clearing process because some of those offers will be based on a resource's estimate of its costs and RTOs/ISOs or Market Monitoring Units may not have perfect information with which to estimate those costs. Additionally, as noted by market monitors, when natural gas spot market prices rise to levels that could result in the short-run marginal costs of some natural gas-fired resources exceeding $1,000/MWh, over-the-counter natural gas markets often lack liquidity or have wide bid-ask spreads, which can make verification challenging, particularly verification of expected costs. At those times, a market participant's expected costs could vary significantly from its actual costs. Although, as discussed further below, only verified cost-based incremental energy offers above $1,000/MWh may be used to calculate LMPs subject to the $2,000/MWh hard cap. We find that, on balance, a hard cap will reasonably limit the adverse impact that any imperfect information about resources' short-run marginal costs during the verification process could have on LMPs. 88. Second, we agree with MISO that a hard cap will be easier to integrate with other market constructs that place caps or upper bounds on various market elements ( e.g., penalty factors associated with shortage pricing or violating transmission constraints). 89. We are not persuaded by comments that a hard cap is duplicative of existing market power mitigation rules because existing market power mitigation provisions in most RTOs/ISOs only apply under certain circumstances, whereas this Final Rule essentially mitigates all incremental energy offers above $1,000/MWh to a level based on short-run marginal costs. Additionally, as noted above, the hard cap is necessary to address concerns about the imperfect information that RTOs/ISOs and/or Market Monitoring Units have about resources' short-run marginal costs during the verification process. 90. Having determined that a hard cap is necessary, we find that $2,000/MWh is a just and reasonable level for that hard cap based on the record in this proceeding. Historically, high natural gas prices during the Polar Vortex resulted in at least one resource with a cost-based incremental energy offer of $1,724/MWh. 199 Based on this experience and noting that it occurred in an otherwise low natural gas price environment, we expect that resources may experience costs that approach but are unlikely to exceed $2,000/MWh. With a hard cap of $2,000/MWh, we find that resources will be able to recover those costs and that LMPs will reflect marginal costs. 200 The Commission has previously relied upon high and volatile natural gas prices as a justification for increasing offer caps. 201 This $2,000/MWh level was also generally supported by Potomac Economics. 202 With respect to treatment of cost-based incremental energy offers above $2,000/MWh, we expect RTOs/ISOs to use such offers to determine merit-order dispatch. We note that the Commission allowed this approach when accepting PJM's current offer cap structure, in which PJM uses cost-based incremental energy offers above $2,000/MWh to determine merit order dispatch but limits cost-based incremental energy offers to $2,000/MWh for purposes of calculating LMPs. 203 199 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 13 (citing PJM 2014 Offer Cap Order I, 146 FERC ¶ 61,041 at P 2). 200 See Envtl. Action, Inc. v. FERC, 939 F.2d 1057, 1064 (D.C. Cir. 1991) (“it is within the scope of the agency's expertise to make such a prediction about the market it regulates, and a reasonable prediction deserves our deference notwithstanding that there might also be another reasonable view.”). See also Michigan Consol. Gas Co. v. F.E.R.C., 883 F.2d 117, 124 (1989) (“It is also quite clear FERC may make predictions—“[m]aking . . . predictions is clearly within the Commission's expertise” and will be upheld if “rationally based on record evidence.”) (citing East Tennessee Natural Gas Co. v. FERC, 863 F.2d 932, 938-39 (1988) (citing Associated Gas Distributors v. FERC, 824 F.2d 981, 1008 (1987)). 201 See California Indep. Sys. Operator Corp., 114 FERC ¶ 61,026, at P 25 (2006) (In CAISO, natural gas prices rose from $3-$4/MMBtu when the bid cap in CAISO was $250/MWh to $14/MMBtu. Based on this information, the Commission found “that raising the bid cap is justified by the well-documented rise in gas prices” and accepted CAISO's proposal to raise the bid cap from $250/MWh to $400/MWh.). 202 Potomac Economics Comments at 8. 203 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 11. 91. We recognize that a $2,000/MWh hard cap leaves some possibility for price suppression when the marginal cost of production legitimately exceeds $2,000/MWh. However, by allowing verified cost-based incremental energy offers in the $1,000/MWh-$2,000/MWh range to set LMPs, we significantly reduce the likelihood of such price suppression, and we find this balanced approach just and reasonable. 92. We decline to hold a technical workshop as suggested by NYISO or a triennial review as suggested by Exelon to determine an appropriate level for the hard cap because there is sufficient evidence in this record to support $2,000/MWh as a just and reasonable value. Based on the record, we decline to adopt a lower hard cap level, such as the $1,500/MWh value TAPS proposes, because this level is demonstrably lower than cost-based incremental energy offers observed during the Polar Vortex. Additionally, the PJM Market Monitor reported that on 54 occasions in early 2015, resources submitted cost-based incremental energy offers at prices above $1,000/MWh. 204 204 Monitoring Analytics, Report on PJM Energy Market Offers January 16 to March 31, 2015, at 2 (May 1, 2015), available at http:// www.monitoringanalytics.com/reports/Reports/2015/IMM_Informational_Filing_Docket_No_EL15-31-000_20150505.pdf . 93. With respect to APPA, NRECA, and AMP's argument that concerns over seams do not justify revising RTO/ISO offer caps, particularly because the Commission accepted PJM's current $2,000/MWh offer cap, we reiterate that the Commission's finding in that order was limited to the facts in that record. In accepting PJM's proposal, the Commission stated that it would not prejudge broader reforms in the price formation proceeding. 205 205 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 55. 94. We decline to hold, as CAISO suggests, a technical workshop on implementation challenges. We expect that any issues regarding the implementation of this Final Rule will be raised by RTOs/ISOs on compliance, and the Commission will address them at that time. We also decline to implement a $400/MWh cap on incremental energy offers that are not cost-based, as some commenters have suggested. We find that the fact that resources rarely submit incremental energy offers above $400/MWh does not indicate that allowing resources to submit incremental energy offers as high as $1,000/MWh which are not cost-based (referred to as “market-based offers” in PJM) will result in unjust and unreasonable rates. 95. In response to MISO's suggestion that future adjustments to the offer cap may be needed in response to market-based solutions that increase demand elasticity or resource mix changes, we decline to speculate as to what changes may or may not be necessary in the future. B. Cost Verification 1. NOPR Proposal 96. In the NOPR, the Commission proposed the requirement that cost-based incremental energy offers above $1,000/MWh be verified by the RTO/ISO or Market Monitoring Unit prior to being used to calculate LMPs (verification requirement). 206 The Commission proposed the following verification requirement: 206 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 56. The costs underlying a resource's cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used for purposes of calculating Locational Marginal Prices. If a resource submits an incremental energy offer above $1,000/MWh and the costs underlying that offer cannot be verified before the market clearing process begins, that resource's incremental energy offer in excess of $1,000/MWh may not be used to calculate Locational Marginal Prices. In such circumstances a resource would be eligible for a make-whole payment if that resource clears the energy market and the resource's costs are verified after-the-fact. 207 207 Id. 97. The Commission reasoned that this requirement would ensure that the proposal results in LMPs that reflect the marginal cost of production during intervals when the marginal resource's short-run marginal cost exceeds $1,000/MWh. Further, in the NOPR, the Commission preliminarily found that the verification requirement was necessary to reduce the potential exercise of market power by resources, which could result in unjust and unreasonable rates. 208 208 Id. P 57. 2. Comments 98. As discussed further below, the Commission received several comments about the proposed verification requirement. Comments about the proposed verification requirement focus on whether it is needed and what type of verification would be acceptable and feasible. A number of commenters generally support the proposed verification requirement, but they express concerns or seek clarification about the proposed verification requirement. 209 209 ISO-NE Comments at 6; NYISO Comments at 2; PJM/SPP Comments at 2-3; TAPS Comments at 12. a. Need for the Verification Requirement 99. Commenters disagree about whether the proposed verification requirement for cost-based incremental energy offers above $1,000/MWh is necessary to reduce the potential exercise of market power. Several commenters support the verification requirement, 210 some asserting that the verification requirement is a critical element of the proposal. 211 210 SCE Comments at 1-2; PG&E Comments at 1-3; NY Transmission Owners Comments at 3. 211 Golden Spread Comments at 3; Delaware Commission Comments at 11; TAPS Comments at 12; NESCOE Comments at 3. 100. OMS contends that the verification requirement protects retail consumers from unlimited and unjustified wholesale price increases. 212 The Delaware Commission and TAPS assert that the verification requirement is necessary to address market power concerns. 213 TAPS states that although it opposes revisions to the offer cap, the proposed verification requirement is needed to protect the integrity of the RTO/ISO markets and will help avoid litigation costs associated with re-running markets after-the-fact in the event that an LMP is subsequently found not to be cost-justified. 214 PG&E and SCE generally support the prevention of unverified incremental energy offers above $1,000/MWh from setting the LMP, although PG&E does not support the proposal overall. 215 212 OMS Comments at 3. 213 Delaware Commission Comments at 11; TAPS Comments at 12-13. 214 TAPS Comments at 12-13. 215 PG&E Comments at 1-3; SCE Comments at 1-2. 101. PJM Joint Consumer Advocates argue that the only way to protect consumers from unfair prices is to verify offers prior to the market clearing process and that fairness demands such a review, even if the verification process is technically complex. PJM Joint Consumer Advocates assert that market-based offers, which are not strictly tied to costs, should not be eligible to set LMP because they would unfairly inflate costs to consumers and result in a windfall for suppliers. 216 216 PJM Joint Consumer Advocates Comments at 5. 102. Other commenters assert that the verification requirement is unnecessary 217 or unduly cumbersome. 218 Potomac Economics and PJM Power Providers argue that cost verification is unnecessary given other RTO/ISO market constructs. 219 Potomac Economics states that the justification for the proposed verification requirement is limited because competition is not diminished during the fuel price spikes that could cause a resource's short-run marginal costs to exceed $1,000/MWh. Potomac Economics also argues that existing RTO/ISO market power mitigation measures address market power concerns. 220 PJM Power Providers state that the verification requirement is unnecessary because resources have the incentive to submit incremental energy offers that reflect actual costs. PJM Power Providers assert that the threat of an investigation from the Commission's Office of Enforcement and possible associated fines incent good behavior and discourage the exercise of market power. 221 Industrial Energy Consumers also state that the NOPR could lead markets to become more complicated and opaque, potentially leading to unintended consequences. 222 217 Potomac Economics Comments at 12; PJM Power Providers Comments at 5. 218 OMS Comments (on behalf of Texas Commission) at 3 n.7. 219 Potomac Economics Comments at 12; PJM Power Providers Comments at 5. 220 Potomac Economics Comments at 12. 221 Exelon Comments at 9; PJM Power Providers Comments at 5 (citing Public Citizen, Inc. v. Midcontinent Indep. Sys. Operator, Inc., 154 FERC ¶ 61,224, at P 88 (2016)). 222 Industrial Energy Consumers Comments at 2. b. Verification Standard 103. The Commission sought comment on the Market Monitoring Unit's or RTO's/ISO's ability to timely verify cost-based incremental energy offers above $1,000/MWh prior to the day-ahead or real-time market clearing process. 223 In response, the Commission received a wide array of comments about the feasibility of the proposed verification requirement and the challenges associated with implementing the requirement. 223 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 59. 104. Many of the comments highlighted the difference between verification of actual costs and verification of expected costs. They noted that because verification has to occur before the market runs, verification of actual costs was more difficult than verification of expected costs. Indeed, several commenters contend that it is not possible prior to the market clearing process to verify that a resource's cost based-incremental energy offer equals that resource's actual costs. 224 Commenters raise two key obstacles to the verification of a resource's actual costs prior to the market clearing process: (1) Some natural gas resources do not know their actual costs at the time they submit offers; and (2) natural gas resource fuel costs are particularly difficult to verify during periods when natural gas supplies are scarce. Each obstacle is discussed in turn below. 224 EEI Comments at 6; Exelon Comments at 11; IRC Comments at 2-3; ISO-NE Comments at 2, 6-7; MISO Comments at 9; PJM/SPP Comments at 12-13; Potomac Economics Comments at 3-4; SPP Market Monitor Comments at 9. i. Resource Cost Uncertainty When Submitting Offers 105. Many commenters, including RTOs/ISOs, market monitors, and generators, assert that because some resources, specifically natural gas resources, do not know their actual fuel procurement costs when they submit incremental energy offers to the RTO/ISO, it is impossible to verify the incremental energy offers of such resources prior to the market clearing process. 225 225 Dominion Comments at 5; Exelon Comments at 16; ISO-NE Market Monitor Comments at 7; ISO-NE Comments at 6; MISO Comments at 9; PJM Market Monitor Comments at 6; PJM/SPP Comments at 10; Potomac Economics Comments at 3-5; SPP Market Monitor Comments at 9. 106. ISO-NE, MISO, and PJM/SPP state that some natural gas resources have not procured fuel by the time that they submit incremental energy offers to the RTO/ISO markets, and thus ISO-NE and PJM/SPP state that such resources often submit offers based on the cost that the resources expect to pay for natural gas on the natural gas spot market. 226 For example, PJM/SPP state that some natural gas resources procure all or part of their natural gas requirements in the daily natural gas spot market, which is more volatile than month-ahead index prices because of changes in commodity prices and weather, as well as interstate natural gas pipeline capacity curtailments and maintenance activities. 227 226 ISO-NE Comments at 5; MISO Comments at 9; PJM/SPP Comments at 9. 227 PJM/SPP Comments at 9-10. 107. Comments from market monitors also suggest that some natural gas resources do not know their actual fuel costs at the time they submit offers. 228 For example, the ISO-NE Market Monitor states that natural gas resources that have not purchased natural gas in advance submit offers based on their best estimate of what they expect to pay for natural gas in real-time. 229 Potomac Economics and the ISO-NE Market Monitor state that resources submit initial incremental energy offers 230 or updates to their cost-based incremental energy offers 231 based on expected, rather than actual costs. Potomac Economics adds that such offers reflect a resource's expectation of its costs, and these costs may be subject to substantial uncertainty and thus cannot be verified in advance. 232 The ISO-NE Market Monitor, Potomac Economics, and the SPP Market Monitor conclude that strict verification of a resource's actual costs prior to the market clearing process is not possible. 233 228 ISO-NE Market Monitor Comments at 7; Potomac Economics Comments at 4; SPP Market Monitor Comments at 9. 229 ISO-NE Market Monitor Comments at 7. 230 Potomac Economics Comments at 4. 231 ISO-NE Market Monitor Comments at 7. 232 Potomac Economics Comments at 4. 233 ISO-NE Market Monitor Comments at 4; Potomac Economics Comments at 3-4; SPP Market Monitor Comments at 9. 108. Generators also state that verification of actual costs may not be possible because some natural gas resources can only submit an estimate of their expected fuel costs. 234 For example, Exelon states that when a resource submits a day-ahead offer, which is due 24-48 hours prior to actual dispatch, that resource must consider numerous costs and may have to make complicated and somewhat imprecise judgments to predict future events, which makes it difficult to quantify and substantiate risks on either an before-the-fact or after-the-fact basis. 235 Additionally, EEI states that a resource that is not committed or not fully committed in the day-ahead market may not procure enough natural gas to meet its full output in the real-time market and may need to purchase fuel in the intra-day natural gas market where prices are significantly higher and more volatile than the day-ahead natural gas market. 236 234 Dominion Comments at 5; Exelon Comments at 11-16. 235 Exelon Comments at 11-17. 236 EEI Comments at 5-6. ii. Cost Verification During Peak Periods 109. Several commenters state that the challenges associated with pre-verification become more acute during stressed system conditions when natural gas supplies are limited, which is precisely when resources may have incremental energy costs above $1,000/MWh. 237 237 See generally Dominion Comments at 4-5; PJM/SPP Comments 11; ISO-NE Comments at 4-5; SPP Market Monitor Comments at 7; PJM Market Monitor Comments at 6; EEI Comments at 6; Exelon Comments at 13-14; PJM Power Providers Comments at 3. 110. PJM states that higher natural gas prices have led to higher cost-based incremental energy offers from resources, but verifying resource costs with natural gas price indices can be challenging because there is not a strong or straightforward correlation between changes in natural gas index prices and the magnitude of changes in cost-based offers, particularly when cost-based incremental energy offers in PJM are high. 238 ISO-NE argues that indices may not fairly represent the fuel prices that resources must pay, particularly when natural gas supplies are tight. 239 ISO-NE notes that there may be scant independent or timely information on natural gas resources' costs during such times. 240 Various commenters explain that during such times, natural gas resources must often purchase natural gas outside of the exchange trading platforms 241 through bilateral deals that are not reported on such exchanges, and that a significant amount of such purchases tends to make natural gas indices less representative of the price natural gas resources pay for natural gas. 242 238 PJM/SPP Comments at 11 (citing Attachment A). Attachment A presents an analysis of cost-based incremental energy offers and natural gas prices during the winters of 2013/14, 2014/15, and 2015/16. The analysis in Attachment A shows that for cost-based offers in the $500/MWh-$750/MWh range, the median gas price corresponding to the range of offers was $10.44/MMBtu in the 2013/14 winter, $15.62 MMBtu in the 2014/15 winter, and $3.75/MMBtu in the 2015/16 winter. 239 ISO-NE Comments at 4-5. 240 Id. 241 Industrial Customers Comments at 16; ISO-NE Comments at 4-5; ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6; SPP Market Monitor Comments at 7. 242 ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6. 111. The ISO-NE., PJM, and SPP market monitors state that cost verification is most challenging when natural gas demand is high because of low liquidity and high bid-ask spreads for natural gas purchased on open exchanges such as the ICE. 243 For example, the PJM Market Monitor and the ISO-NE Market Monitor state that the natural gas market is least transparent on days with very high electric demand and that the ICE index is likely to be unsuitable for verification purposes because there are either no completed trades reported, a low number of completed gas trades ( i.e., low liquidity), or the bid-ask spread is so wide as to be meaningless. 244 The SPP Market Monitor states that the risk inherent in determining accurate fuel costs from natural gas indices is acceptable in most periods, but that the risk increases to unacceptable levels during extremely stressed fuel supply conditions. 245 Comments from generators also suggest that natural gas indices become less reliable during periods when natural gas supplies are limited and natural gas prices spike. 246 Dominion and Exelon assert that purchasing natural gas outside of an exchange through marketers or bilateral deals also increases the risks that a natural gas resource faces when it formulates its bid, and can increase the error associated with a resource's estimate of its actual costs. 247 243 ISO-NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6; SPP Market Monitor Comments at 7. 244 ISO-NE Market Monitor Comments at 7-8; PJM Market Monitor Comments at 6. 245 SPP Market Monitor Comments at 7. 246 EEI Comments at 6; Exelon Comments at 13-14; PJM Power Providers Comments at 3. 247 Dominion Comments at 5; Exelon Comments at 13-14. c. Feasibility of Verification Requirement 112. The Commission sought comment on the feasibility of the proposed verification requirement. 248 As discussed further below, ISO-NE, MISO, and NYISO state that current mitigation procedures could satisfy the proposed verification requirement if the Commission clarifies that the verification process can include expected, rather than actual, costs. 249 Several commenters express concerns that timely verification of a resource's actual short-run marginal costs is not possible within the timeframe of the RTO/ISO day-ahead and real-time market clearing process. 250 248 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 59, 73. 249 See infra PP 126-127. 250 Exelon Comments at 11; Industrial Customers Comments at 13-16; ISO-NE Market Monitor Comments at 9; Joseph Margolies Comments at 13; Potomac Economics Comments at 3-4; SPP Market Monitor Comments at 2, 7, 9. 113. For example, Potomac Economics states that time constraints will make the proposal infeasible if the proposed verification requires that resource cost data be collected and fully validated to actual cost prior to market clearing. 251 The ISO-NE Market Monitor states that the lack of solid information about natural gas prices on high-volatility, low-liquidity days makes validation of a resource's expected short-run marginal costs difficult, particularly if many resources seek to update their cost-based incremental energy offers. 252 The PJM Market Monitor notes that in PJM, a large volume of data, including information from approximately 420 gas-fired resources and about 35 gas trading points, must be processed to review cost-based incremental energy offers. 253 The SPP Market Monitor states that verification prior to market clearing may not be feasible in SPP given the tight timeline, particularly during sudden fuel shortages and fuel price spikes, and adds that it would need additional technical capabilities for such verification. 254 The SPP Market Monitor states that the proposal could also negatively affect RTO/ISO market monitors' ability to conduct timely market power mitigation under the proposed timeline because market monitors would be required to perform cost verification and market mitigation before completion of the market clearing process. 255 251 Potomac Economics Comments at 3-4. 252 ISO-NE Market Monitor Comments at 9. 253 PJM Market Monitor Comments at 7. 254 SPP Market Monitor Comments at 2, 7, 9, 10-11. 255 Id. at 9. 114. Industrial Customers argue that market monitors cannot be expected to have the ability to assess the legitimacy of the cost component of resource offers in real-time. 256 Industrial Customers add that even if a resource has a natural gas invoice with a high price and provides it to the market monitor, this alone does not provide adequate consumer protection because the market monitor must investigate, understand, and accept the dynamics that led to that invoice. 257 256 Industrial Customers Comments at 14. 257 Industrial Customers Comments at 19. 115. Citing CAISO's prior comments about practical implementation challenges associated with before-the-fact verification, Industrial Customers argue that the proposal in the NOPR may not be beneficial because pre-verification presents significant challenges given time constraints. 258 KEPCo/NCEMC states that RTOs/ISOs may not be in a position to verify cost-based incremental energy offers prior to market clearing without substantial investment in both new technology and significant changes to the existing RTO/ISO tariffs and business practice manuals. 259 KEPCo/NCEMC argues that the verification requirement involves substantial technological and regulatory costs for wholesale market participants, which KEPCo/NCEMC asserts are unwarranted given the limited nature of the problem with the current RTO/ISO offer caps. 260 258 Id. at 14-16 (citing CAISO Post-Technical Workshop Comments, Docket No. AD14-14-000, at 4-6 (Mar. 6, 2015)). 259 KEPCo/NCEMC Comments at 5. 260 Id. 116. EEI maintains that the NOPR proposal is heavily dependent on having a verification process that is not so cumbersome as to prevent a resource's cost based incremental energy offer from being verified in time to be used in the LMP calculation. It argues that the use of make-whole payments would not serve the Commission's goal of having clearing prices that reflect the true marginal cost of production, taking into account all physical constraints. 261 NEI states that the manner in which the verification is performed is a key concern, and without a simple and efficient process, there is risk that the LMP will not reflect the true costs of operating the system because it will exclude offers above the cap. NEI maintains that an alternative approach would be warranted if market monitors cannot validate incremental energy offers in excess of $1,000/MWh quickly and efficiently. 262 Competitive Suppliers contend that the proposed verification requirement would result in cost-based offers above $1,000/MWh being unable to set the LMP because cost verification prior to the market clearing process is not possible. 263 261 EEI Comments at 5. 262 NEI Comments at 4. 263 Competitive Suppliers Comments at 17-18. 117. Competitive Suppliers argue that removing the offer cap entirely or increasing it significantly would alleviate any challenges inherent in a before-the-fact cost verification process. 264 Similarly, NEI states that instead of the verification requirement, the Commission should lift caps to a level that does not artificially constrain LMPs. 265 264 Id. 265 NEI Comments at 4. 118. Midcontinent Joint Consumer Advocates and TAPS argue that it is possible to perform the proposed cost verification prior to the market clearing process. 266 Midcontinent Joint Consumer Advocates state that the MISO Market Monitor has publicly confirmed its ability to verify offers prior to market clearing and that it currently tracks fuel prices that could be used to make adjustments to gas and fuel costs included in a MISO resource's cost-based incremental energy offer. 267 According to TAPS, MISO's current process for developing and updating cost-based incremental offers for resources is workable because the vast majority of resources will never experience cost levels close to $1,000/MWh, and the resources that are likely to reach such levels should have already provided the Market Monitoring Unit with up-to-date information about their heat rates, which will allow the Market Monitoring Unit to quickly calculate cost-based incremental energy offers for such resources. 268 TAPS states that MISO's current methodology for verification of cost-based incremental offers could be modified and adapted in all RTOs/ISOs. 269 266 Midcontinent Joint Consumer Advocates Comments at 5; TAPS Comments at 13-15. 267 Midcontinent Joint Consumer Advocates Comments at 5. 268 TAPS Comments at 13-14. 269 Id. at 14-15. d. Uplift Payments 119. Several stakeholders commented on the after-the-fact review of costs in the event that the RTO/ISO or Market Monitoring Unit is unable to verify a resource's incremental energy offer above $1,000/MWh prior to the market clearing process. 270 MISO states that market participants should be required to consult with the Market Monitoring Unit before the submission of an offer in order for that market participant to be eligible for make-whole payments after-the-fact, and asserts that market participants should not be eligible for cost recovery above their offers just because in hindsight, their offers were below their actual costs. 271 PG&E states that if a cost-based incremental energy offer is verified after the market has run, energy cleared from such an offer should be compensated on an “as bid” basis. 272 PG&E maintains that if a cost-based incremental energy offer cannot be verified even after the market has run, then that resource's [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2016-28320. Public record. Not legal advice.