Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, 87770-87800 [2016-28320]

Download as PDF 87770 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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 Federal Energy Regulatory Commission. ACTION: Final rule. AGENCY: 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 SUMMARY: 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. Effective Date: This rule will become effective February 21, 2017. DATES: 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 sradovich on DSK3GMQ082PROD with RULES4 Paragraph numbers I. Introduction ......................................................................................................................................................................................... II. Background ......................................................................................................................................................................................... A. Offer Caps in RTOs/ISOs ........................................................................................................................................................... B. Offer Caps Waivers and Tariff Changes .................................................................................................................................... III. Need for Reform ................................................................................................................................................................................ A. Comments ................................................................................................................................................................................... 1. Comments That Support the Preliminary Finding That Current Offer Caps are Unjust and Unreasonable ................. 2. Comments that Oppose Reforming Current Offer Caps ..................................................................................................... 3. Generally Applicable Offer Cap Reforms ........................................................................................................................... B. Determination ............................................................................................................................................................................. IV. Offer Cap Reforms ............................................................................................................................................................................ A. Offer Cap Structure .................................................................................................................................................................... 1. NOPR Proposal ..................................................................................................................................................................... 2. Comments ............................................................................................................................................................................. 3. Determination ....................................................................................................................................................................... B. Cost Verification ......................................................................................................................................................................... 1. NOPR Proposal ..................................................................................................................................................................... 2. Comments ............................................................................................................................................................................. 3. Determination ....................................................................................................................................................................... C. Resource Neutrality .................................................................................................................................................................... 1. NOPR Proposal ..................................................................................................................................................................... 2. Comments ............................................................................................................................................................................. 3. Determination ....................................................................................................................................................................... V. Other Issues ........................................................................................................................................................................................ A. Virtual Transactions ................................................................................................................................................................... 1. Comments ............................................................................................................................................................................. 2. Determination ....................................................................................................................................................................... B. External Transactions ................................................................................................................................................................. 1. Comments ............................................................................................................................................................................. 2. Determination ....................................................................................................................................................................... VI. Other Comments ............................................................................................................................................................................... A. Verification Requirement Details .............................................................................................................................................. 1. Comments ............................................................................................................................................................................. 2. Determination ....................................................................................................................................................................... B. Impact of Offer Cap Reforms on Other Market Elements ........................................................................................................ 1. Comments ............................................................................................................................................................................. 2. Determination ....................................................................................................................................................................... VII. Requests Beyond the Scope of this Proceeding ............................................................................................................................. A. Comments ................................................................................................................................................................................... B. Determination ............................................................................................................................................................................. VIII. Information Collection Statement ................................................................................................................................................. IX. Regulatory Flexibility Act Certification .......................................................................................................................................... VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 E:\FR\FM\05DER4.SGM 05DER4 1 7 10 14 15 16 16 20 27 34 42 44 44 45 77 96 96 98 139 148 148 149 156 160 160 161 172 178 179 192 199 200 200 207 209 210 213 214 214 218 219 223 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 87771 Table of Contents Paragraph numbers X. Environmental Analysis .................................................................................................................................................................... XI. Document Availability ..................................................................................................................................................................... XII. Effective Date and Congressional Notification .............................................................................................................................. Regulatory Text APPENDIX: List of Short Names/Acronyms of Commenters sradovich on DSK3GMQ082PROD with RULES4 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 costbased incremental energy offer reasonably reflects that resource’s actual or expected costs. 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 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. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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. 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 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. PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 225 226 229 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. 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. 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). E:\FR\FM\05DER4.SGM 05DER4 87772 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES4 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 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 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 6 Price Formation Notice, Docket No. AD14–14– 000. 7 Price Formation Notice, Docket No. AD14–14– 000 at 2. 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). VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 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 realtime 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 pricequantity 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 9 Id. P 73. 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). 10 See, PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 are cost-based, but PJM applies a hard cap that limits incremental energy offers to $2,000/MWh when calculating LMPs.11 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 costbased incremental energy offers to $2,000/MWh for purposes of calculating 11 PJM Interconnection, L.L.C., 153 FERC ¶ 61,289, at P 25 (2015) (PJM 2015 Offer Cap Order). 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). E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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 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. A. Comments 1. Comments That Support the Preliminary Finding That Current Offer Caps are Unjust and Unreasonable sradovich on DSK3GMQ082PROD with RULES4 16. Several commenters, for various reasons, support the Commission’s preliminary finding in the NOPR that existing offer caps in RTOs/ISOs are 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. 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. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 shortrun 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 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 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. 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). PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 87773 because artificially suppressing dayahead 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 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 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 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 costjustified 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 30 Competitive Suppliers Comments at 9. Joint Consumer Advocates Comments at 3–4. 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. 34 CEA Comments at 2–3; EEI Comments at 3–4. 35 CAISO Comments at 4. 36 Id. at 4–5. 31 Midcontinent E:\FR\FM\05DER4.SGM 05DER4 87774 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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 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 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 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 sradovich on DSK3GMQ082PROD with RULES4 37 ISO–NE Comments at 1–3. 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. 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. 43 ODEC Comments at 3–4. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 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 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 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. 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. PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 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 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 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 55 AF&PA Comments at 2–3. Comments at 6–7. 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. 60 See supra P 2. 61 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 70. 62 Id. P 71. 56 TAPS E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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. 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 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 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 63 Id. P 48. 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. 70 PJM Market Monitor Comments at 12. 71 EEI Comments at 4. 72 CAISO Comments at 14; Exelon Comments at 22. sradovich on DSK3GMQ082PROD with RULES4 64 See VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 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 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 33. APPA, NRECA, and AMP assert that the NOPR runs counter to the Commission’s usual practice of 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. 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. 79 PG&E Comments at 1–2. 80 NY Transmission Owners Comments at 4–5. 81 Direct Energy Comments at 5–6. PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 87775 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 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. 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 82 APPA, NRECA, and AMP Comments at 5–6. 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. 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. 83 Id. E:\FR\FM\05DER4.SGM 05DER4 87776 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES4 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. 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. 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 86 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 13– 17. 87 See supra P 5. 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. 88 We VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 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 longterm 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. 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 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 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. 91 Competitive Suppliers Comments at 9; EEI Comments at 5. 92 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 70– 71. 93 Id. P 74. 94 Id. PP 45, 49 (citing Notice Inviting Comments, Docket No. AD14–14–000 at 2). PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 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. 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: (1) A resource’s incremental energy offer must be capped at the higher of $1,000/MWh or that resource’s costbased 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 95 16 E:\FR\FM\05DER4.SGM U.S.C. 824e (2012). 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations that resource is dispatched and the resource’s costs are verified after-thefact. 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 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 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 costbased; 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.. sradovich on DSK3GMQ082PROD with RULES4 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 96 NOPR, 97 See FERC Stats. & Regs. ¶ 32,714 at P 53. id. P 55. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 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 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 costbased, 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 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 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. 101 MISO Comments at 7. 102 Id. at 7. 103 NY Transmission Owners Comments at 2–3. 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. 107 Exelon refers to this threshold as a ‘‘marketbased offer cap.’’ See, e.g., Exelon Comments at 1, 7–10. PO 00000 Frm 00009 Fmt 4701 Sfmt 4700 87777 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 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 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 52. Some commenters argue that offer caps that limit the incremental energy offers that resources can submit should 108 Exelon Comments at 9–10. at 10. 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. 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). 109 Id. E:\FR\FM\05DER4.SGM 05DER4 87778 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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 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 54. PJM Power Providers assert that resources should be able to submit costbased 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 sradovich on DSK3GMQ082PROD with RULES4 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 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. 120 MISO Comments at 6. 121 Id. at 7. 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. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 57. However, other commenters argue that incremental energy offers above $1,000/MWh, even if they are costbased, 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 126 See supra P 17. 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. 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 127 CEA PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 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 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 59. CAISO, ISO–NE, and NYISO support a hard cap. CAISO asserts that, assuming it were able to verify costbased 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 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. 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. 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.’’ E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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 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 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 141 ISO–NE sradovich on DSK3GMQ082PROD with RULES4 Comments at 2–3. Comments at 8. 143 See infra P 69. 144 MISO Comments at 13. 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. 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 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 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 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 inframarginal 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 142 NYISO VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 149 ISO–NE Market Monitor Comments at 13–14. Market Monitor Comments at 1. 151 Id. at 4. 152 ISO–NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6; SPP Market Monitor Comments at 7. 153 NY Transmission Owners Comments at 3–4; New Jersey Commission Comments at 9. 154 NY Transmission Owners Comments at 4. 150 PJM PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 87779 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 costbased incremental energy offers in electricity markets and increase LMPs.156 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 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 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 155 Id. 156 New Jersey Commission Comments at 9. Market Monitor Comments at 6, 13. 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. 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. 157 SPP E:\FR\FM\05DER4.SGM 05DER4 87780 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations generators to minimize their costs if these costs can be passed on to consumers.164 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 costbased incremental energy offers that reflect their short-run marginal costs and that those offers should be able to set the LMP.168 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 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 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 164 Industrial Customers Comments at 19–20. 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. 169 MISO Comments at 13. 170 Id. 171 MISO Comments at 13. 172 Exelon Comments at 21; EEI Comments at 4. 173 Competitive Suppliers Comments at 13. sradovich on DSK3GMQ082PROD with RULES4 165 Competitive VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 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 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 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 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 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 182 Id. 174 Competitive Suppliers Comments at 14; PJM/ SPP Comments at 6; Dominion Comments at 4. 175 Dominion Comments at 4. 176 ISO–NE Comments at 3. 177 NYISO Comments at 8. 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. 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. PO 00000 Frm 00012 Fmt 4701 Sfmt 4700 at 11. 183 Midcontinent Joint Consumer Advocates Comments at 4. 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. 190 Dominion Comments at 3. E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES4 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 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 dayahead 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. 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 costbased, 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 191 NESCOE Comments at 2. 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. 192 The VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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. 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. 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. 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 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. 194 See supra P 2. 195 Specifically CAISO, ISO–NE, MISO, NYISO, and SPP. PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 87781 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 shortrun 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 196 See 197 See E:\FR\FM\05DER4.SGM infra PP 105–108. supra P 63. 05DER4 87782 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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-thecounter 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 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. 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 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. 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 realtime 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: sradovich on DSK3GMQ082PROD with RULES4 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. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 PO 00000 Frm 00014 Fmt 4701 Sfmt 4700 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 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 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 welldocumented 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. 204 Monitoring Analytics, Report on PJM Energy Market Offers January 16 to March 31, 2015, at 2 (May 1, 2015), available at http:// E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 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 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 costbased (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 marketbased 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 sradovich on DSK3GMQ082PROD with RULES4 1. NOPR Proposal 96. In the NOPR, the Commission proposed the requirement that costbased 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: The costs underlying a resource’s costbased 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 www.monitoringanalytics.com/reports/Reports/ 2015/IMM_Informational_Filing_Docket_No_EL1531-000_20150505.pdf. 205 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 55. 206 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 56. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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 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 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 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.211 100. 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 87783 litigation costs associated with rerunning 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.215 101. 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 marketbased 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.216 102. 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 214 TAPS 215 PG&E Comments at 12–13. Comments at 1–3; SCE Comments at 1– 2. 207 Id. 216 PJM 208 Id. P 57. 209 ISO–NE Comments at 6; NYISO Comments at 2; PJM/SPP Comments at 2–3; TAPS Comments at 12. 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. 212 OMS Comments at 3. 213 Delaware Commission Comments at 11; TAPS Comments at 12–13. PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 Joint Consumer Advocates Comments at 5. 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)). E:\FR\FM\05DER4.SGM 05DER4 87784 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations and opaque, potentially leading to unintended consequences.222 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. 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. 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.225 106. ISO–NE, MISO, and PJM/SPP state that some natural gas resources have not procured fuel by the time that 222 Industrial Energy Consumers Comments at 2. FERC Stats. & Regs. ¶ 32,714 at P 59. 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. 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. sradovich on DSK3GMQ082PROD with RULES4 223 NOPR, VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 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.227 107. 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.233 108. 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 226 ISO–NE Comments at 5; MISO Comments at 9; PJM/SPP Comments at 9. 227 PJM/SPP Comments at 9–10. 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. 234 Dominion Comments at 5; Exelon Comments at 11–16. PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 substantiate risks on either an beforethe-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 ii. Cost Verification During Peak Periods 109. Several commenters state that the challenges associated with preverification 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.237 110. 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 235 Exelon Comments at 11–17. Comments at 5–6. 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. 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. 236 EEI E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations indices less representative of the price natural gas resources pay for natural gas.242 111. 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 sradovich on DSK3GMQ082PROD with RULES4 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 242 ISO–NE Market Monitor Comments at 8; PJM Market Monitor Comments at 6. 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. 248 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 59, 73. 249 See infra PP 126–127. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 actual short-run marginal costs is not possible within the timeframe of the RTO/ISO day-ahead and real-time market clearing process.250 113. 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.255 114. 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.257 115. Citing CAISO’s prior comments about practical implementation 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. 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. 256 Industrial Customers Comments at 14. 257 Industrial Customers Comments at 19. PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 87785 challenges associated with before-thefact verification, Industrial Customers argue that the proposal in the NOPR may not be beneficial because preverification presents significant challenges given time constraints.258 KEPCo/NCEMC states that RTOs/ISOs may not be in a position to verify costbased 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.260 116. 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.263 117. 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 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. 261 EEI Comments at 5. 262 NEI Comments at 4. 263 Competitive Suppliers Comments at 17–18. 264 Id. E:\FR\FM\05DER4.SGM 05DER4 87786 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations level that does not artificially constrain LMPs.265 118. 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 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 afterthe-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 cost265 NEI Comments at 4. 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. 270 Competitive Suppliers Comments at 19; MISO Comments at 10; PG&E Comments at 3; PJM Power Providers Comments at 4. 271 MISO Comments at 10. 272 PG&E Comments at 3. sradovich on DSK3GMQ082PROD with RULES4 266 Midcontinent VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 based incremental energy offer cannot be verified even after the market has run, then that resource’s cleared energy should instead be compensated at the LMP.273 PJM Power Providers and Competitive Suppliers assert that even after-the-fact verification of a resource’s costs will be challenging, and, according to Competitive Suppliers, it will be particularly challenging for natural gas resources that have complex fuel supply arrangements.274 120. Competitive Suppliers state that in some instances, a resource may not be able to use the RTO’s/ISO’s verification process to set the market clearing price (for offers above $1,000/ MWh) and in such rare cases, it may be necessary to compensate that resource through an uplift payment based on after-the-fact cost verification.275 Competitive Suppliers assert that if a resource incurs justifiable and demonstrable short-run marginal costs, those costs should be recovered so that the resource does not operate at a loss and so that the resource is not discouraged from offering supply to the market.276 121. NEI states that, given that the Commission’s price formation reforms are aimed at reducing the use of out-ofmarket payments, NEI is disappointed by the NOPR proposal to include uplift payments as a fall back if before-the-fact cost verification proves infeasible in practice.277 However, Direct Energy states that if a resource’s verified costbased incremental energy offer exceeds the cap, that resource should be entitled to full cost recovery of RTO/ISO approved costs through uplift.278 e. Specific Proposals for the Verification Requirement 122. Given the concerns about verification of actual costs, several commenters, including RTOs/ISOs,279 Market Monitoring Units,280 and other stakeholders,281 request that the Commission clarify that if it is not possible to verify a resource’s actual costs prior to setting LMP, it will accept a process that verifies that a resource’s incremental energy offer reasonably reflects that resource’s expected costs. 123. Several commenters maintain that a prior-to-the-market-clearing verification process that requires costbased offers be equal to actual costs will likely result in fewer incremental energy offers above $1,000/MWh that are eligible to set LMP.282 For example, EEI states that its primary concern with the NOPR is the verification process and whether it is workable.283 The ISO–NE Market Monitor and PJM/SPP state that there is a trade-off between the level of precision of the cost-based offer verification, the number of offers that will be eligible to set LMPs, and the level of uplift.284 124. Several commenters ask the Commission to indicate the types of verification processes it would accept.285 ISO–NE., MISO, and NYISO state that their current process for developing and updating cost-based incremental energy offers, known as reference levels, could comply with the proposal as clarified to include estimated costs.286 125. CAISO states that the simplest method of verifying cost-based incremental energy offers would involve reviewing a broker quote or procurement invoice provided as evidence of a resource’s costs, but CAISO questions whether such information would be sufficient.287 CAISO predicts that incremental energy offers above $1,000/MWh are not likely to be eligible to set the clearing price in CAISO and that instead a resource with costs above $1,000/MWh would receive an uplift payment, assuming that the resource’s costs were verified after-thefact.288 126. PJM/SPP state that the principles outlined in the NOPR are sound, provided that the Final Rule allows RTOs/ISOs flexibility to design verification procedures that are consistent with current RTO/ISO rules.289 PJM/SPP outline conceptual initial proposals for verification, but stress the need to provide RTOs/ISOs with latitude to develop the final verification process with stakeholders.290 PJM presents a possible verification process that involves an automatic screen to filter out unreasonably high offers and to create a range of reasonableness based on an 273 Id. 274 Competitive Suppliers Comments at 19; PJM Power Providers Comments at 4. 275 Competitive Suppliers Comments at 20–21. 276 Id. at 21. 277 NEI Comments at 4. 278 Direct Energy Comments at 3. 279 ISO–NE Comments at 4–7; NYISO Comments at 2; PJM/SPP Comments at 12–13. 280 Potomac Economics Comments at 3–4; ISO– NE Market Monitor Comments at 4. 281 EEI Comments at 6–7; Exelon Comments at 17. PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 282 CEA Comments at 5; EEI Comments at 5. Comments at 5. 284 ISO–NE Market Monitor Comments at 5; PJM/ SPP Comments at 13. 285 CEA Comments at 6; IRC Comments at 2. 286 ISO–NE Comments at 6; MISO Comments at 8; NYISO Comments at 2. 287 CAISO Comments at 11. 288 Id. 289 PJM/SPP Comments at 2–3. 290 Id. at 14–21. 283 EEI E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES4 index of natural gas prices, the bid/ask spread, and resource heat rates.291 PJM states that the verification requirement could use a screening process that determines whether certain resources’ incremental energy offers in a given area are within ten percent or $100/MWh of a benchmark offer based on a natural gas price index.292 SPP states that it could develop additional rules that facilitate resources’ submission of the fuel cost component of their cost-based incremental energy offers that is consistent with the resource’s actual costs where possible, or that is a reasonably accurate representation of those costs. SPP states that given the need to approximate fuel costs that are difficult to verify, in most cases such a verification process could be subject to a reasonable margin of error.293 127. ISO–NE states that if its current cost verification process is acceptable to the Commission, then the offer cap proposal may be workable and would help improve price formation if high fuel prices cause generation costs to exceed $1,000/MWh.294 MISO contends that its current process to establish and adjust cost-based offers can be used to verify incremental energy offers above $1,000/MWh.295 NYISO also states that its current review process of a resource’s incremental energy costs could be used to satisfy the proposed verification requirement.296 128. The ISO–NE Market Monitor states that the Commission should revise the proposed verification requirement to permit use of ISO–NE’s current Commission-approved process where a resource can update its costbased incremental energy offer, which occurs through a ‘‘Fuel Price Adjustment.’’ 297 The ISO–NE Market Monitor states that ISO–NE’s Fuel Price Adjustment mechanism balances the desire to reflect resource costs in costbased incremental energy offers, the limited information the ISO–NE Market Monitor has available to verify costs, and the need to deter abuse.298 The ISO–NE Market Monitor explains that ISO–NE’s market power mitigation software automatically calculates costbased incremental energy offers for resources, which may be based on a day-ahead fuel price index.299 129. Potomac Economics states that MISO’s current process for developing 291 Id. at 15–16. at 16–17. 293 Id. at 19. 294 ISO–NE Comments at 6. 295 MISO Comments at 8. 296 NYISO Comments at 3. 297 ISO–NE Market Monitor Comments at 5–10. 298 Id. at 5. 299 Id. at 6. 292 Id. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 and updating reference levels would comply with a Final Rule which clarified that before-the-fact verification of a resource’s expected costs is acceptable.300 Potomac Economics explains that in MISO, cost-based offers are calculated on the day before every operating day based on next-day fuel price indices.301 In real-time, the MISO Market Monitor (i.e., Potomac Economics), reviews natural gas prices on ICE at various delivery points, and if natural gas prices rise significantly compared to the next-day fuel index, the MISO Market Monitor adjusts the costbased incremental energy offers of any affected resources.302 Potomac Economics adds that a MISO resource can also consult with the Market Monitor and request to raise its costbased offer beyond this adjustment if the resource provides supporting information, which may or may not be approved.303 130. Potomac Economics explains that a NYISO resource may also request to update its cost-based incremental energy offer through a software process that automatically permits such an increase, provided the increase does not exceed a predetermined threshold.304 Potomac Economics maintains that NYISO may need to adjust the validation threshold to account for periods of unusually high fuel price volatility, but that with such an adjustment, NYISO’s current verification process could comply with the proposal.305 131. The PJM Market Monitor explains that resource owners in PJM are responsible for submitting their own cost-based offers and fuel cost policies, and that fuel costs are an essential part of the verification process.306 The PJM Market Monitor states that it does not have the authority to tell a resource owner what its fuel cost is or what its offer should be, but it does have the authority to verify cost-based offers, to discuss cost issues with resource owners, and to refer resource owners to the Commission for rule violations and for the attempted or actual exercise of market power.307 It states that it is essential that the Commission impose 300 Potomac Economics Comments at 5. at 4. 302 Id. In MISO, cost-based offers are referred to as reference levels. 303 Id. at 5. 304 Id. NYISO states that a resource that updates the fuel type or fuel cost information associated with its cost-based incremental energy offer must make supporting documentation available for NYISO’s review after-the-fact. See NYISO Comments at 4. 305 Potomac Economics Comments at 6. 306 PJM Market Monitor Comments at 4–5. 307 Id. at 5. 301 Id. PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 87787 significant penalties for rule violations determined during the after-the-fact review. According to the PJM Market Monitor, a resource should be required to have in place a fuel cost policy that has been approved by both the PJM Market Monitor and PJM before the resource is able to submit an offer in excess of $1,000/MWh.308 The PJM Market Monitor states that if a resource’s cost-based incremental energy offer above $1,000/MWh is used in the market clearing process, the PJM Market Monitor would perform a timely after-the-fact review to determine whether a resource’s offer was based upon the best information available at the time the resource submitted the cost-based incremental energy offer.309 The PJM Market Monitor states that, in cases where an offer above $1,000/MWh is not permitted, the PJM Market Monitor would perform a timely afterthe-fact review to determine the actual incurred costs of a resource, and uplift would be paid if the costs exceeded the market clearing price.310 Any uplift payments for such offers would be based on the actual gas cost incurred. The PJM Market Monitor also recommends that the $1,000/MWh offer cap apply to a resource’s ‘‘operating rate,’’ which is calculated by adding a resource’s incremental offer to its noload offer.311 132. The PJM Market Monitor also maintains that it is essential that any verification process include a rigorous and timely after-the-fact review and a requirement that a resource follows the cost-based offer submission rules and abides by its approved fuel cost policy. The PJM Market Monitor states that the verification process requires strong compliance incentives, and the Commission should impose significant penalties if a resource violates the costbased incremental energy offer guidelines.312 133. Commenters representing generator and load interests also proposed verification processes. Competitive Suppliers and NEI state that lifting the offer cap to a level that does not artificially constrain LMPs is preferable to developing a verification process, as removing the cap allows the market price to convey accurate information of the state of the system even during high stress.313 308 Id. 309 Id. at 6. at 7–8. 310 Id. 311 Id. at 2. at 7. 313 Competitive Suppliers Comments at 18; NEI Comments at 4. 312 Id. E:\FR\FM\05DER4.SGM 05DER4 87788 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations 134. Competitive Suppliers prefer no verification requirement but contends that if the Commission requires that all cost-based incremental energy offers above $1,000/MWh be verified, the RTO/ISO and the generator should be able to identify a set of accepted criteria and data inputs such that resources can submit offers that can be accepted and thus eligible to set LMP.314 Competitive Suppliers state that PJM’s Cost Development Guidelines provide a means of verifying resource costs and may provide an alternative approach to the proposed verification requirement.315 135. Exelon proposes that the Commission require RTOs/ISOs to adopt tariff provisions that will permit timely review and approval of resources’ cost-based offers based on a resource-specific ‘‘safe harbor’’ formula that is agreed upon in advance.316 Exelon proposes that, at a minimum, the safe harbor formula should include a ten percent uncertainty component and a fuel cost component based on a daily natural gas index, natural gas adders, balancing costs, transportation costs, and a risk adder.317 136. Dominion supports a verification process that uses fuel estimates based on recent prices, historical prices during similar conditions, or a combination of both.318 Dominion would support allowing market participants to submit cost-based offers within a reasonable range of a reference price that would be based on a historical fuel price index or an average of ask prices within a given fuel market, and that offers which fall in the range of that reference price and clear the market should be eligible to set LMP.319 137. The New Jersey and Pennsylvania Commissions and OPSI maintain that in order to implement the proposal in PJM, resources should be required to have a fuel cost policy approved by the Market Monitoring Unit prior to submission of cost-based incremental energy offers above $1,000/ MWh.320 The Pennsylvania Commission states that pre-approved resource fuel cost policies in PJM would speed up the verification process, foster market stability, and provide certainty to 314 Competitive Suppliers Comments at 19. 315 Id. sradovich on DSK3GMQ082PROD with RULES4 316 Exelon Comments at 11. 317 Id. at 17–20 (citing Testimony of Leslie O. Dedrickson at 29–31). 318 Dominion Comments at 5. 319 Id. 320 New Jersey Commission Comments at 12–13; Pennsylvania Commission Comments at 9; OPSI Comments at 7–9. This issue was also raised in comments in PJM’s offer flexibility proposal in Docket No. ER16–372–000. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 resources.321 The New Jersey Commission and OPSI assert that resource fuel cost policies should be derived from a verifiable, algorithmic, and systematic approach consistent with the PJM Market Monitor’s fuel cost policy guidelines.322 The Delaware and Pennsylvania Commissions and OPSI argue that PJM should clarify the role of PJM and the PJM Market Monitor in the review and approval of fuel cost policies and assert that the PJM Market Monitor should have the authority to verify offers above $1,000/MWh.323 138. SCE argues that each RTO/ISO should utilize its own stakeholder processes to develop specific verification rules, which may reflect regional factors such as differences in market power mitigation processes and region-specific costs such as emissions and greenhouse gas costs.324 3. Determination 139. We adopt the NOPR proposal and clarify that each RTO/ISO or Market Monitoring Unit is required to verify that any incremental energy offer above $1,000/MWh reasonably reflects the associated resource’s actual or expected costs prior to using that offer to calculate LMPs. We find that this verification requirement is necessary for incremental energy offers above $1,000/ MWh because market power concerns are heightened when a resource’s shortrun marginal costs exceed $1,000/MWh. 140. Based on the record, it is not practical to require that RTOs/ISOs or Market Monitoring Units verify a resource’s actual costs in all circumstances because a resource may not know its actual short-run marginal costs at the time it submits an incremental energy offer to the RTO/ISO for various reasons, including the timing of natural gas procurement. Accordingly, we clarify that an RTO/ ISO or a Market Monitoring Unit must verify that cost-based incremental energy offers above $1,000/MWh reasonably reflect a resource’s actual or expected costs. Under this requirement, the verification process for cost-based incremental offers above $1,000/MWh must ensure that a resource’s cost-based incremental energy offer reasonably reflects that resource’s actual or expected costs. 321 Pennsylvania Commission Comments at 9. Jersey Commission Comments at 13; OPSI Comments at 8 (citing Monitoring Analytics, Fuel Cost Policy Guidelines: Gas Replacement Cost (Sept. 24, 2015), available at http:// www.monitoringanalytics.com/reports/ Market_Messages/Messages/ IMM_Fuel_Cost_Policy_Guidelines_20150924.pdf). 323 Delaware Commission Comments at 12; OPSI Comments at 7–9. 324 SCE Comments at 1–2. 322 New PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 141. The RTO/ISO or Market Monitoring Unit, as prescribed in the RTO/ISO tariff and consistent with Order No. 719,325 must verify the costs within a cost-based incremental energy offer above $1,000/MWh before that offer is used to calculate LMP, subject to the condition that such offers are capped at $2,000/MWh for purposes of calculating LMP.326 To create such a verification process, we expect that the RTO/ISO would build on its existing mitigation processes for calculating or updating cost-based incremental energy offers.327 However, we appreciate statements from RTOs/ISOs, market monitors, and others about potential verification processes for incremental energy offers above $1,000/MWh. We recognize that the verification process for incremental energy offers may be a fact-specific inquiry, and we have previously provided Market Monitoring Units with flexibility to make casespecific determinations.328 Given the potential complexities involved in verifying incremental energy offers as well as the Commission’s recognition of the need for proper mitigation methods in energy markets, we will require that RTOs/ISOs explain in their compliance filings what factors will be considered by the RTO/ISO or its Market Monitoring Unit in the verification process for cost-based incremental energy offers above $1,000/MWh and whether such factors are currently considered in existing market power mitigation provisions or whether new practices or tariff provisions are necessary given the verification requirement adopted in this Final Rule. Therefore, we disagree that the verification requirement is needlessly cumbersome because RTOs/ISOs may build on existing processes for market power mitigation. 142. Most RTOs/ISOs prohibit incremental energy offers above $1,000/ MWh, a prohibition that some market 325 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281, at PP 370–375 (2008), order on reh’g, Order No. 719–A, FERC Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719–B, 129 FERC ¶ 61,252 (2009). See also 18 CFR 35.28(g)(3)(iii)(B) (2016). 326 Pursuant to 18 CFR 35.28(g)(3)(iii)(B), either the internal or external market monitor can ‘‘provide the inputs required to conduct prospective mitigation . . . including, but not limited to reference levels, identification of system constraints, and cost calculations.’’ 18 CFR 35.28(g)(3)(iii)(B) (2016). However, prospective mitigation may only be carried out by an internal market monitor if the RTO/ISO has a hybrid Market Monitoring Unit structure. 18 CFR 35.28(g)(3)(iii)(D) (2016). 327 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 63. 328 See New England Power Generators Association, Inc. v. ISO New England Inc., 144 FERC ¶ 61,157, at P 62 (2015). E:\FR\FM\05DER4.SGM 05DER4 sradovich on DSK3GMQ082PROD with RULES4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations monitors characterize as a backstop market power mitigation measure.329 The offer cap adopted in this Final Rule retains the backstop function that the current $1,000/MWh offer cap plays in existing RTO/ISO market power mitigation because it limits incremental energy offers that are not cost-based to $1,000/MWh. Under this Final Rule, incremental energy offers below $1,000/ MWh will remain subject to existing market power mitigation measures. However, this Final Rule will require that all incremental energy offers equal to and above $1,000/MWh be costbased, which essentially requires mitigation of all incremental energy offers above $1,000/MWh. 143. In this way, the verification requirement requires RTOs/ISOs to make only an incremental change to their existing market power mitigation procedures because the market power mitigation provisions that apply to incremental energy offers below $1,000/ MWh will be unchanged. While in this Final Rule we increase the offer cap for cost-based incremental energy offers, we also subject offers above $1,000/MWh to additional market power mitigation in the form of the verification requirement. The verification requirement is designed to ensure that a cost-based incremental energy offer above $1,000/MWh is not an attempt by the associated resource to exercise market power. The verification requirement is part-and-parcel with the increase of the offer cap for cost-based incremental energy offers. We find that it would be inappropriate to raise the offer cap without imposing a verification requirement. The verification requirement thus serves as an additional backstop market power mitigation measure.330 144. Contrary to Potomac Economics’ assertion that competition is not diminished when short-run marginal costs rise above $1,000/MWh, we find that market power concerns are heightened during such periods because short-run marginal costs in this range may indicate that very few resources are available to provide additional supply. Supply may be limited during such periods because of fuel supply limitations or the physical limitations of resources (e.g., ramping constraints). Accordingly, resources with available supply during such periods likely face little competition, particularly in realtime, and may therefore be able to exercise market power. We find that the 329 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 23. existing Commission regulations establish that misrepresenting costs when submitting cost-based incremental energy offers as part of a supply offer may be in violation of 18 CFR 35.41(b) (2016) and 18 CFR 1c.2(a)(2) (2016). 330 Moreover, VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 verification requirement reasonably addresses market power concerns associated with incremental energy offers above $1,000/MWh because such offers will be required to be cost-based, which should deter attempts by resources to exercise market power. 145. As discussed above, this Final Rule will require RTOs/ISOs to limit incremental energy offers to $2,000/ MWh when calculating LMPs, which may be below the cost-based incremental energy offer of a resource. Thus, we revise the verification requirement proposed in the NOPR as indicated below and add new language (underlined below) to account for any uplift associated with the $2,000/MWh hard cap and adopt the following verification requirement: The costs underlying a resource’s costbased 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. 146. We will retain the proposal in the NOPR which ensures that, if a resource’s incremental energy offer above $1,000/MWh is not verified but that resource is nonetheless dispatched, that resource would be eligible to receive an uplift payment to recover its verified costs. The basis of the uplift payment would be the difference between a given resource’s energy market revenues and that resource’s actual short-run marginal costs of the MWs dispatched, as verified after-thefact by the RTO/ISO or Market Monitoring Unit.331 We find that such uplift payments are necessary given the challenges associated with the verification processes, to ensure that resources have an incentive to offer into RTO/ISO energy markets, and to ensure that resources are compensated for the service they provide. 147. This Final Rule will permit regional variation in the process for 331 The Commission notes that the clarification regarding use of a resource’s actual or expected short-run marginal costs during the verification process that occurs prior to the market clearing process is not applicable to such uplift payments. Any such uplift payment, which is paid after-thefact, must be based on a resource’s actual short-run marginal costs. PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 87789 treating incremental energy offers above $1,000/MWh that the RTO/ISO or Market Monitoring Unit cannot verify prior to the start of the market clearing process. For example, the RTO/ISO could have procedures to change the incremental energy offer to $1,000/MWh or to mitigate that offer to a level below $1,000/MWh pursuant to other applicable market power mitigation provisions. C. Resource Neutrality 1. NOPR Proposal 148. In the NOPR, the Commission proposed the following resource neutrality requirement: All resources, regardless of type, are eligible to submit cost-based incremental energy offers in excess of $1,000/MWh.332 The Commission reasoned that this requirement would ensure that the eligibility to submit cost-based incremental energy offers in excess of $1,000/MWh would not be applied in an unduly discriminatory or unduly preferential manner.333 The Commission also stated that the proposed resource neutrality requirement is consistent with prior orders related to the offer cap in PJM and MISO.334 2. Comments 149. Several commenters support the proposed resource neutrality requirement.335 For example, MISO supports the resource neutrality requirement and notes that the MISO tariff currently allows any resource, regardless of type, to establish a costbased reference level.336 MISO adds that some resources could be constrained by the $1,000/MWh cap because they may be unable to provide evidence of high fuel costs.337 150. Commenters disagree about whether demand response resources should be able to submit incremental energy offers above $1,000/MWh. Some commenters argue that demand response resources should be treated the same as other physical generation resources that provide offers.338 332 NOPR, FERC Stats. & Regs, ¶ 32,714 at P 69. 333 Id. 334 Id. (citing MISO 2014/15 Offer Cap Order, 150 FERC ¶ 61,083 at P 16; PJM 2014/15 Offer Cap Order, 150 FERC ¶ 61,020 at P 39). 335 EEI Comments at 1, 3; Ohio Commission Comments at 12; MISO Comments at 12. 336 MISO Comments at 12 (citing MISO Tariff, Module D, 64.1.4.a, 64.3.a, and 64.1.4.h). 337 Id. 338 API Comments at 12–13; Competitive Suppliers Comments at 23–24; Exelon Comments at 23 (citing PJM Manual 11 2.3.3); Industrial Customers Comments at 28; PJM Market Monitor Comments at 12–13. E:\FR\FM\05DER4.SGM 05DER4 87790 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES4 Additionally, MISO questions why a demand response resource should be prevented from submitting an offer at the same level (in $/MWh) as physical resources.339 151. However, other commenters argue that demand response should not be able to submit incremental energy offers above $1,000/MWh. PJM/SPP argue that the proposed offer cap revisions should not apply to demand response resources because demand response resource offers are intended to capture foregone commercial revenues, not the short-run marginal cost of reducing output.340 ISO–NE asserts that a demand response resource’s costs would be based on its marginal opportunity cost of foregone consumption, which could routinely exceed $1,000/MWh or $2,000/MWh, and that verifying such costs could not be accomplished on short notice. ISO– NE surmises that allowing demand resources to submit incremental energy offers above $1,000/MWh could create perverse incentives and may give physical resources the incentive to move behind the meter to exploit asymmetries in the application of the offer cap. Accordingly, ISO–NE requests that the Commission carefully consider its position on verification of the actual costs of demand response resources.341 152. The New Jersey Commission argues that in the absence of a comprehensive definition of short-run marginal costs for demand response resource offers, demand response resources should not be permitted to offer and set the market clearing price above the Commission’s determined offer cap.342 The Pennsylvania Commission asserts that demand response resources should not be eligible to set LMP and should be treated as price takers, asserting that such resources do not generally exhibit competitive behavior in energy markets because the energy revenues of such resources are de minimis relative to their capacity market revenues.343 153. Several commenters express concerns about whether RTOs/ISOs or Market Monitoring Units can verify the costs of demand response resources. For example, ISO–NE asserts that a demand response resource’s costs would be based on that resource’s marginal opportunity cost of foregone 339 MISO Comments at 7. Comments at 5. 341 ISO–NE Comments at 7–8. 342 New Jersey Commission Comments at 18. 343 Pennsylvania Commission Comments at 14 (citing PJM, Demand Response Operations Market’s Activity Report: February 2016 (Feb. 16, 2016), Fig. 23; Monitoring Analytics, LLC, State of the Markets Report for PJM, Vol. 1., Fig. 10 (Mar. 10, 2016)). 340 PJM/SPP VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 consumption and other information that is difficult to validate, particularly if the demand response resource’s costs increase significantly from the prior day.344 PJM/SPP state that it is not clear what demand response resource costs could be validated to justify an offer above the $1,000/MWh offer cap.345 The Pennsylvania Commission states that with the limited exception of on-site backup generation costs, the incremental energy costs of demand response capacity resources are largely unknown.346 ISO–NE urges the Commission to carefully consider whether the verification of actual costs should be imposed on a resourceneutral basis, and explains its concerns regarding its ability to timely verify the offers of demand response resources.347 AEMA argues that it is impractical, if not impossible, to verify the costs of a demand response resource in the same manner as a physical generation resource, particularly before-the-fact.348 AEMA also cites a prior Commission order on ISO–NE’s Order No. 745 compliance where the Commission found that ‘‘unlike with supply resources, it would be very difficult to develop a competitive offer or reference price to which to mitigate each demand response resource.’’ 349 AEMA asserts that there is no need to create an additional verification requirement for demand response resources, because the Commission has recognized that comparability does not require identical treatment.350 154. AEMA requests that the Commission clarify that the offer cap proposed in the NOPR only impacts demand response resources that participate in energy markets and would not apply to demand resources that exclusively participate in capacity markets.351 AEMA explains that demand response resources that participate exclusively in capacity 344 ISO–NE Comments at 7–8. Comments at 5. 346 Pennsylvania Commission Comments at 14. 347 ISO–NE Comments at 7–8. 348 AEMA Comments at 7–8. 349 Id. at 8 (citing ISO New England Inc., 138 FERC ¶ 61,042, at P 138 (2012)). 350 Id. at 8–9 (citing Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890–B, 123 FERC ¶ 61,299, at P 216 (2008), order on reh’g, Order No. 890–C, 126 FERC ¶ 61,228, order on clarification, Order No. 890–D, 129 FERC ¶ 61,126 (2009); Indep. Market Monitor for PJM v. PJM Interconnection, L.L.C., 155 FERC ¶ 61,059, at P 31 (2016) (‘‘comparability does not require identical application to demand response resources and generation resources of PJM’s offer cap and the must-offer requirement’’)). 351 Id. at 3. 345 PJM/SPP PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 markets do not make incremental energy offers. AEMA explains that capacityonly demand response resources are only dispatched on a reliability-based trigger that determines the price the demand resource is paid as opposed to an offer price-based trigger that does not represent the LMP at which the customer wishes to be dispatched, or the costs of the customer to curtail its load. AEMA asserts that forcing these resources to make ‘‘incremental energy offers’’ in the energy market would drive them away from participation.352 155. AEMA requests that the Commission continue to allow demand response resources to submit offers up to the offer cap in energy markets and not impose additional verification requirements on demand response resource energy market offers beyond what has already been accepted.353 AEMA asserts that the Final Rule should not impact existing or proposed methods for monitoring and evaluating demand resource offers in energy markets or create additional verification hurdles for demand resource offers beyond those that currently exist.354 3. Determination 156. We adopt the NOPR proposal and find that resources with costs above $1,000/MWh should be able to submit cost-based incremental energy offers to recover their costs, regardless of the type of resource. Prohibiting a particular set of resources from submitting costbased incremental energy offers above $1,000/MWh could preclude them from recovering their costs. 157. In the NOPR the term ‘‘resource’’ referred to all supply resources, including demand response resources, that offer incremental energy to RTO/ ISO energy markets.355 As such, a demand response resource that submits incremental energy offers to the energy market based on short-run marginal cost would be subject to the verification requirement if that incremental energy offer exceeds $1,000/MWh. For such a resource, the short-run marginal cost may equal its opportunity costs. 158. We recognize that the verification process for demand response resources will necessarily differ from the verification process for generation resources, as noted by ISO– NE and AEMA. The Commission has 352 Id. at 3–5. at 5–6. 354 Id. at 2–3, 7–9. 355 This is consistent with prior uses of the term. See, e.g., Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 825, 81 FR 42,882 (June 30, 2015), FERC Stats. & Regs. ¶ 31,384, at P 98 (2016). 353 Id. E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations recognized that demand response resources should receive comparable, but not necessarily identical treatment to generation resources.356 However, we decline AEMA’s request to exempt demand response resources that submit incremental energy offers in RTO/ISO energy markets from any additional verification requirements associated with this Final Rule, because such an exemption does not constitute comparable treatment. However, as noted above,357 this Final Rule does not prescribe how RTOs/ISOs should verify cost-based incremental energy offers above $1,000/MWh, including offers from demand response resources. 159. Finally, we find that the New Jersey and Pennsylvania Commissions’ comments that demand response resources should not be able to set LMP are beyond the scope of this Final Rule, which only applies to incremental energy offers above $1,000/MWh, and not the general eligibility of demand response resources to set LMPs in RTO/ ISO energy markets. We clarify, however, that reforms adopted in this Final Rule, which provide that resources are eligible to submit costbased incremental energy offers in excess of $1,000/MWh and require that those offers be verified, do not apply to capacity-only demand response resources that do not submit incremental energy offers in energy markets. V. Other Issues A. Virtual Transactions 160. Although the Commission preliminarily found in the NOPR that virtual supply offers and virtual demand bids (virtual transactions) could not provide a cost basis for offers above $1,000/MWh, it sought comment about whether prohibiting virtual transactions above $1,000/MWh could limit hedging opportunities, present opportunities for manipulation or gaming, create market inefficiencies, or have other undesirable consequences.358 1. Comments 161. CAISO states that virtual transactions do not face short-run marginal production costs and would thus be unable to justify costs above $1,000/MWh.359 However, CAISO notes that if physical resources can submit incremental energy offers above $1,000/ MWh, then virtual participants should also be able to bid above $1,000/MWh to arbitrage those physical offers.360 162. ISO–NE states that market participants should be able to submit virtual supply offers at levels as high as offers from physical resources to ensure that there is a liquid supply of offers that can compete with physical resources in the day-ahead market under all market conditions, which can reduce the potential exercise of market power during tight day-ahead conditions.361 ISO–NE asserts that if the Commission adopts a new hard cap, there is no cost-basis or market power rationale to limit virtual supply offers below the level of any hard cap.362 163. PJM argues that virtual transactions should be permitted to exceed $1,000/MWh or be subject to a reasonableness screen because virtual transactions increase competition in the day-ahead markets and reduce market share, and thus reduce market power.363 MISO states that prohibiting virtual transactions above $1,000/MWh could limit hedging opportunities which could increase the price differentials between the day-ahead and real-time energy markets.364 MISO adds that revising the offer cap for virtual transactions could conceivably expose other market participants to high prices but notes that MISO already has mitigation measures in place for virtual transactions and that years of market experience have shown that such manipulation concerns are improbable.365 164. NYISO states that cost-based incremental energy offers, interchange transactions (e.g., imports and exports), and virtual transactions should be capped at the level of the hard cap, which will allow market participants to continue to compete to the maximum extent practicable.366 NYISO also argues that a hard cap is appropriate for virtual transactions because such transactions are based on price expectations as opposed to verifiable costs.367 SPP states that it takes no position on the application of the proposed reforms to virtual transactions.368 359 CAISO sradovich on DSK3GMQ082PROD with RULES4 356 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ¶ 31,322, at P 66, order on reh’g and clarification, Order No. 745–A, 137 FERC ¶ 61,215 (2011) (‘‘as a general matter demand response providers and generators should be subject to comparable rules that reflect the characteristics of the resource.’’). 357 See supra P 141. 358 NOPR, FERC Stats. & Regs ¶ 32,714 at PP 64, 73. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 Comments at 13. 360 Id. Comments at 8. at 8–9. 363 PJM/SPP Comments at 27. 364 MISO Comments at 18; see also PJM/SPP Comments at 27–28. 365 MISO Comments at 18. 366 NYISO Comments at 7–8. 367 Id. at 7. 368 PJM/SPP Comments at 28. 87791 165. Potomac Economics states that competitive virtual transactions should be permitted to exceed $1,000/MWh when real-time prices are expected to exceed $1,000/MWh.369 Potomac Economics states that although virtual transactions do not have production costs, they do have marginal costs, and notes that the marginal cost of selling virtual energy in the day-ahead market is the expected cost of buying the energy in the real-time market.370 Potomac Economics states that virtual transactions support the competitive performance of day-ahead markets and thus argues that it is important to structure the rules for virtual transactions in a manner that does not impede their participation in the market.371 166. Potomac Economics proposes that virtual transactions be permitted to exceed $1,000/MWh when real-time LMPs are expected to exceed $1,000/ MWh for more than a specified period (e.g., 30 minutes).372 The PJM Market Monitor argues that market participants should not be permitted to submit virtual transactions above $1,000/MWh because increasing the offer cap on virtual transactions would create opportunities for the exercise of market power and manipulation of markets and permit resource owners to avoid the requirement that incremental energy offers above $1,000/MWh be costbased.373 The PJM Market Monitor states there is no evidence that virtual supply offers have increased competition or would increase competition in extreme circumstances.374 The PJM Market Monitor recommends that if the Commission wishes to permit some virtual transactions to exceed $1,000/ MWh, the Commission should: (1) Limit virtual transactions above $1,000/MWh to liquid trading hubs; (2) require market participants to explain why virtual offers or bids above $1,000/MWh are appropriate; and (3) subject such virtual transactions to a ‘‘reasonableness screen’’ and an after-the-fact review for whether they resulted in manipulation or market power.375 The PJM Market Monitor states that the asserted benefits of virtuals with respect to hedging, competition, and price convergence have not been empirically established, and, thus, it is unnecessary to create 361 ISO–NE 362 Id. PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 369 Potomac Economics Comments at 10. 370 Id. 371 Id. 372 Id. at 9–10. Market Monitor Comments at 11; PJM Market Monitor Answer at 6. 374 PJM Market Monitor Answer at 5. 375 PJM Market Monitor Comments at 11–12. 373 PJM E:\FR\FM\05DER4.SGM 05DER4 87792 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations market power risks when revising the offer cap.376 167. Separately, the PJM Market Monitor recommends that up-tocongestion transactions in PJM be excluded from any offer cap reforms stating that because up-to-congestion transactions are spread bids between nodes there is no reason to relax the current rules that govern such transactions.377 168. Several commenters argue that the Commission should allow virtual transactions to exceed $1,000/MWh.378 Some commenters focus on the use of virtual transactions to hedge physical transactions and argue that virtual transactions should thus be subject to the same offer caps as physical resources.379 Dominion states that in extreme winter conditions, a physical resource that faces a start-up risk and is likely to receive a day-ahead award may submit a virtual demand bid to hedge against the potential outage in realtime.380 Exelon also argues that hedging the risk of physical transactions through virtual transactions is especially important when the system is stressed, and that doing so may improve market performance by converging day-ahead and real-time prices.381 Competitive Suppliers assert that the same argument articulated in the NOPR for having a uniform offer cap across regions demands similar treatment of virtual transactions, imports, and emergency demand response across regions.382 169. Dominion states that limiting the ability to submit virtual transactions above $1,000/MWh to physical resources with verified cost-based incremental energy offers above $1,000/ MWh in order to allow such resources to hedge would minimize concerns about market manipulation.383 The PJM Market Monitor responds that Dominion’s proposal creates a significant risk of manipulation because Dominion does not propose to limit the virtual bids to the cost-based offer of the generator.384 sradovich on DSK3GMQ082PROD with RULES4 376 PJM Market Monitor Answer at 5. 377 PJM Market Monitor Comments at 11; PJM Market Monitor Answer at 6. 378 Competitive Suppliers Comments at 23–24; Dominion Comments at 7; Exelon Comments at 23– 24; ISO–NE Comments at 8; PJM/SPP Comments at 27; SPP Market Monitor Comments at 12; NY Department of State Comments at 6. 379 SPP Market Monitor Comments at 12; Competitive Suppliers Comments at 23–24; NY Department of State Comments at 6; Dominion Comments at 7. 380 Dominion Comments at 7. 381 Exelon Comments at 23–24. 382 Competitive Suppliers Comments at 23. 383 Dominion Comments at 7. 384 PJM Market Monitor Answer at 6. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 170. Several other commenters argue that virtual transactions should be prohibited from submitting transactions above $1,000/MWh.385 For example, several commenters argue that virtual transactions should not be permitted to exceed $1,000/MWh because allowing transactions in this range could raise clearing prices without a commensurate increase in short-run marginal production costs.386 Six Cities argues that permitting virtual transactions to submit offers above the $1,000/MWh cap would be inconsistent with the Commission’s goals of allowing recovery of actual production costs in excess of the cap and establishing LMPs consistent with actual production costs under extreme market conditions.387 TAPS argues that the Commission does not need to allow virtual transactions to exceed $1,000/MWh to encourage price convergence between the day-ahead and real-time markets.388 171. Some commenters argue, as the PJM Market Monitor does, that allowing virtual transactions above the $1,000/ MWh cap could lead to undesirable consequences, such as creating the opportunity for market manipulation and the exercise of market power.389 For example, SCE cautions that allowing virtuals above $1,000/MWh would undermine the purpose of having a backstop for existing market power mitigation rules.390 APPA, NRECA, and AMP state that although they oppose the idea, any proposal to allow virtual transactions above $1,000/MWh must be accompanied by an assurance that the RTO/ISO and/or Market Monitoring Unit will be able to address any gaming or anti-competitive conduct.391 PG&E asks that the Commission direct market monitors to study the potential impacts and gaming opportunities associated with permitting virtual transactions above $1,000/MWh before revising any caps on virtual transactions.392 Midcontinent Joint Consumer Advocates state that while it generally supports applying the same offer cap to 385 APPA, NRECA, and AMP Comments at 19; Industrial Customers Comments at 28–29; Ohio Commission Comments at 14; New Jersey Commission Comments at 17–18; Six Cities Comments at 3. 386 Industrial Customers Comments at 28–29; New Jersey Commission Comments at 17–18; Six Cities Comments at 3; Ohio Commission Comments at 14; TAPS Comments at 20–21. 387 Six Cities Comments at 4. 388 TAPS Comments at 21. 389 APPA, NRECA, and AMP Comments at 19; ODEC Comments at 1; KEPCo/NCEMC Comments at 5; New Jersey Commission Comments at 18; PJM Market Monitor Comments at 11–12; TAPS Comments at 21. 390 SCE Comments at 2. 391 APPA, NRECA, and AMP Comments at 19. 392 PG&E Comments at 3–4. PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 physical and virtual transactions, the issue should be monitored to ensure that inappropriate virtual transactions do not affect real-time energy prices.393 The Delaware Commission recommends that virtual transactions in PJM be limited to $400/MWh.394 2. Determination 172. In light of the comments received and our adoption of a $2,000/MWh hard cap, we find that it is just and reasonable to permit market participants to submit virtual transactions up to $2,000/MWh. We do not require that virtual transactions be subject to the cost verification described above. Allowing virtual transactions above $1,000/MWh could improve price convergence between day-ahead and real-time markets.395 An offer cap that is lower for virtual transactions than for physical resources could increase divergence between day-ahead and realtime LMPs. This finding is consistent with prior Commission precedent, which finds it is reasonable to permit market participants to submit virtual transactions at levels commensurate with the levels that real-time LMPs can reach.396 173. We find that market participants should be allowed to submit virtual transactions up to the hard cap, as they can today. As such, this Final Rule is therefore less likely to result in unintended consequences associated with capping virtual transactions at a level below the hard cap. For example, capping virtual transactions at $1,000/ MWh when the incremental energy offers used to calculate LMPs are capped at $2,000/MWh could encourage some market participants to place virtual demand bids at $1,000/MWh, a transaction that may be profitable if real-time prices exceed $1,000/MWh but would not contribute to day-ahead and real-time price convergence. 174. Under this Final Rule, LMPs may rise above $1,000/MWh. By permitting virtual transactions to exceed $1,000/ MWh, we preserve a market participant’s ability to use virtual 393 Midcontinent Joint Consumer Advocates Comments at 9. 394 Delaware Commission Comments at 14. The Delaware Commission recommends that in PJM, virtual transactions and incremental energy offers that are not cost-based be limited to $400/MWh. 395 PJM Interconnection, L.L.C., 139 FERC ¶ 61,057 (2012). 396 Id. PP 123–126. In that order, the Commission found that ‘‘if virtual traders and demand cannot submit higher bids in the day-ahead market [commensurate with the $/MWh value that realtime LMPs can reach if shortage pricing is in effect], that market may not converge with prices in the real-time market during times when PJM experiences shortage conditions in the real-time market.’’ Id. P 124. E:\FR\FM\05DER4.SGM 05DER4 sradovich on DSK3GMQ082PROD with RULES4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations transactions to hedge its exposure to real-time LMPs above $1,000/MWh. Otherwise, if virtual transactions are limited to $1,000/MWh, as proposed in the NOPR, a market participant would be barred from placing virtual transactions commensurate with its market risks. 175. We also find that allowing virtual transactions above $1,000/MWh may add liquidity to day-ahead markets. Permitting virtual transactions in the $1,000/MWh—$2,000/MWh range could result in additional demand bids and supply offers (i.e., virtual demand bids and virtual supply offers) and will thus allow virtual transactions to continue to perform the functions that they do today by adding liquidity to the day-ahead market. 176. We recognize that virtual transactions, by their nature, cannot be subjected to the type of cost-verification discussed above. However, in response to comments arguing that virtual transactions above $1,000/MWh will raise LMPs above verifiable costs and/or result in market power abuse, we note that Market Monitoring Units currently monitor for anti-competitive behavior by market participants. While they are not required to do so, if RTOs/ISOs determine that additional measures are necessary to address any concerns that arise from permitting virtual transactions up to $2,000/MWh, RTOs/ ISOs may propose such additional measures in a separate filing under section 205 of the Federal Power Act. 177. Dominion proposes to limit the ability to submit virtual transactions above $1,000/MWh to physical resources that have cost-based offers above $1,000/MWh. We find that Dominion’s proposal to limit virtual transactions to certain market participants would be unduly discriminatory. Such a limitation would treat market participants differently depending on whether they owned physical generation assets, and would be unduly discriminatory because it would limit the benefits of virtual transactions above $1,000/MWh to those participants with physical assets. Further, such a limitation could limit the other potential benefits of virtual transactions above $1,000/MWh, such as increased liquidity and increased convergence between day-ahead and real-time LMPs. Additionally, we find that the PJM Market Monitor’s and Potomac Economics’ proposals to limit virtual transactions above $1,000/MWh to certain time periods or certain locations lack sufficient detail and record evidence to make a finding that either proposal is just and reasonable. Finally, we clarify that this Final Rule VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 87793 does not apply to up-to-congestion transactions in PJM, because such transactions are spread bids and not virtual supply offers or virtual demand bids. even when PJM LMPs exceed $1,000/ MWh because such purchases and sales will benefit the market and provide electric supplies by allowing the lowest cost energy to serve customers.404 PJM adds that imports may also defer B. External Transactions operational emergency procedures in 178. In the NOPR, the Commission extreme situations.405 stated that external RTO/ISO resources 182. PJM explains that under PJM’s (i.e., imports) would not be eligible to current rules, economic transactions are submit cost-based incremental energy capped at the maximum energy price offers above $1,000/MWh because RTO/ (absent congestion and losses) of ISO processes to develop cost-based $2,700/MWh while emergency import incremental energy offers for mitigation transactions are not. PJM states that the purposes typically only apply to value of lost load may exceed this level internal RTO/ISO resources.397 The and states that PJM is thus willing to Commission added, however, that it pay more than $2,700/MWh to procure would consider RTO/ISO proposals to emergency energy to prevent load verify cost-based incremental energy shedding.406 PJM notes that the offers from external transactions in their verification of import’s cost would have respective compliance filings.398 The to follow a different process than Commission also sought comment on internal resources because the resource whether the offer cap proposal should behind the import is frequently apply to imports and whether a cost unknown.407 verification process for import 183. SPP states that verifying the costs transactions is feasible.399 of imports could be problematic because it is difficult to obtain cost information 1. Comments from resources outside of SPP.408 SPP 179. CAISO maintains that the asks the Commission to allow regional consistent treatment of internal flexibility for this issue, noting that it resources and external resources (e.g., would investigate the issue further in imports) is key to an efficient market response to any Final Rule issued in this and to avoid unintended proceeding.409 400 CAISO surmises that consequences. 184. According to the PJM Market capping import offers to a level below Monitor, 99.99 percent of PJM imports the cap that internal resource are price takers but imports that are not incremental energy offers are subject to price takers should continue to be could reduce supply offers from imports limited to $1,000/MWh offers.410 during periods when natural gas prices Potomac Economics contends that in the West rise to a level that would external transactions should be eligible justify LMPs above $1,000/MWh.401 to submit offers above $1,000/MWh 180. ISO–NE states that it cannot when prices in the real-time market verify the costs associated with energy exceed $1,000/MWh for more than a import transactions in real-time.402 ISO– specified period of time (e.g., 30 NE explains that an importer’s actual minutes). Potomac Economics also cost to import power into ISO–NE from asserts that Coordinated Transaction an adjacent market is the adjacent Schedules should be exempt from the market’s real-time LMP, which is proposed reforms because they reflect a determined at the same time as ISO– forecast of the price spread between NE’s LMP. ISO–NE adds that, given the RTO/ISO markets and thus would not lack of organized markets in some set the LMP in either market.411 control areas adjacent to ISO–NE., it is 185. The SPP Market Monitor states unclear how actual costs would be that the proposed offer cap requirements verified for import transactions from should apply to imports because those areas. Accordingly, ISO–NE imports have the same potential impact requests additional guidance from the on LMPs as internal resources. Commission about the application of the However, the SPP Market Monitor proposed rule to imports and exports.403 acknowledges that it is more 181. PJM asserts that non-emergency challenging to verify the offers of imports should be allowed to submit offers above $1,000/MWh to ensure that 404 PJM/SPP Comments at 25. economic import transactions occur 405 Id. 397 NOPR, FERC Stats. & Regs ¶ 32,714 at P 63. 398 Id. 399 Id. PP 63, 73. Comments at 13. 400 CAISO 401 Id. 402 ISO–NE Comments at 9. 403 Id. PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 406 Id. at 26 (citing PJM, Intra-PJM Tariffs, OATT, Tariff Operating Agreement, Attachment K– Appendix, section 3.2.3.A). 407 Id. 408 Id. at 27. 409 Id. 410 PJM Market Monitor Comments at 10. 411 Potomac Economics Comments at 9–10. E:\FR\FM\05DER4.SGM 05DER4 87794 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations imports as compared to offers from internal SPP resources because the SPP market monitor may have limited access to the cost data of external resources.412 186. Several commenters assert that imports should be able to offer above $1,000/MWh provided the costs in their offers are verified beforehand,413 and some commenters say it is possible to develop a workable solution for such verification.414 For example, the New Jersey Commission argues that imports that clear the PJM capacity auctions, which are pseudo-tied, will have shortrun marginal production costs that are available for the market monitor to review, and should thus be permitted to offer into the PJM energy market above $1,000/MWh when their costs exceed $1,000/MWh.415 Midcontinent Joint Consumer Advocates explain that offers from imports are provided in the dayahead market and then only scheduled in real-time, and imports cannot set real-time LMPs in MISO.416 However, Midcontinent Joint Consumer Advocates state that if imports are the source of higher prices in MISO markets, then it would be important to verify the costs of imports and in such cases, Midcontinent Joint Consumer Advocates would support verification for imports so that all suppliers are treated equally.417 The Delaware Commission supports the NOPR proposal to require verification of exchange transactions provided the process in an exporting region is not less objective or rigorous than the process in the importing region.418 187. Powerex asks the Commission to consider adopting a verification process for external resources that is distinct from the process used for internal resources because the two resource types differ.419 Powerex states that verifying external resource costs is challenging in WECC because large hydroelectric storage facilities in the Pacific Northwest do not have easily calculable and verifiable short-run marginal costs, and because CAISO does not require that import offers be associated with a specific resource.420 As an alternative, Powerex suggests that 412 SPP Market Monitor Comments at 11. Commission Comments at 13; Midcontinent Joint Consumer Advocates Comments at 8; Ohio Commission Comments at 13; Six Cities Comments at 3. 414 Midcontinent Joint Consumer Advocates Comments at 8; Six Cities Comments at 3; CEA Comments at 7–8. 415 New Jersey Commission Comments at 18. 416 Midcontinent Joint Consumer Advocates Comments at 8. 417 Id. 418 Delaware Commission Comments at 13. 419 Powerex Comments at 7–8. 420 Id. at 8–9. sradovich on DSK3GMQ082PROD with RULES4 413 Delaware VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 the Commission could direct the RTOs/ ISOs to implement an offer cap tied to prevailing market prices, such as capping offers from external resources at the higher of $1,000/MWh or 120 percent of the highest market price index report in the region for the previous seven days.421 TAPS and APPA, NRECA, and AMP assert that the Commission should give individual RTOs/ISOs the discretion to determine whether to allow imports to submit costbased incremental energy offers over $1,000/MWh.422 188. Several commenters argue that limiting external resources to $1,000/ MWh offers may dissuade them from offering electricity to the RTO/ISO in periods when it is most needed.423 For example, CEA states that in light of the Commission’s price formation proceeding, there is no compelling reason to adopt an asymmetrical offer cap for internal resources and imports and questions the wisdom of excluding external transactions when price signals indicate scarcity and extreme conditions.424 Powerex states that the Western Interconnection has a robust market for energy and ancillary services outside of CAISO and that non-CAISO resources may make the economically rational choice to sell power to a nonCAISO customer if CAISO has a lower offer cap compared to the non-CAISO WECC bilateral market.425 189. NYISO and Competitive Power Providers state that all market transactions, including imports and virtual transactions, should be capped at the level of the hard cap, which will allow for a greater degree of competition.426 190. Some commenters discussed emergency imports. For example, PJM Power Providers agrees with PJM that the Commission should not apply the proposed offer requirements to emergency imports because an offer cap on emergency energy or emergency load reductions would limit PJM’s ability to procure sufficient resources and could threaten reliability.427 191. However, the PJM Market Monitor argues that emergency imports above $1,000/MWh should be subject to cost verification before they are eligible to set LMP in PJM and asserts that such 421 Id. at 9. Comments at 19–20; APPA, NRECA, and AMP Comments at 18–19. 423 NY Transmission Owners Comments at 5–6; CEA Comments at 7–8; NY Department of State Comments at 5; Powerex Comments at 7–8. 424 CEA Comments at 7–8. 425 Powerex Comments at 7–8. 426 Competitive Suppliers Comments at 23–24; NYISO Comments at 7. 427 PJM Power Providers Answer at 6–7. 422 TAPS PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 imports currently have an unmitigated opportunity to exercise market power in PJM markets.428 The PJM Market Monitor states that the rules of competitive markets should apply, even during emergency conditions.429 The PJM Market Monitor adds that verifying the costs of emergency imports is feasible because they occur infrequently.430 PJM Market Monitor asserts that PJM/SPP offer no rationale for exempting emergency imports from the proposed offer cap requirements, which the PJM Market Monitor states are most critical during emergency situations.431 2. Determination 192. We find that it is just and reasonable to permit economic exchange transactions (i.e., imports and exports) to offer up to the level of the $2,000/ MWh hard cap. We do not require that import or export transactions above $1,000/MWh be subject to the verification requirement prior to the market clearing process. 193. While in the NOPR the Commission proposed to make imports ineligible to offer above $1,000/MWh, i.e., to prohibit imports from making such offers, we now are persuaded that such a prohibition could discourage imports at times when they are most needed. Imports benefit the market because they offer additional supply and increase competition. A prohibition on imports above $1,000/MWh would discourage external resources with short-run marginal costs above $1,000/ MWh from supplying energy to the RTO/ISO market, even though the market is willing to purchase that supply, and such a prohibition would thus put upward pressure on energy prices. We applied this rationale above in adopting the offer structure requirement and find that it applies equally to imports. Additionally, similar to the rationale outlined above for virtual transactions, allowing imports to offer up to $2,000/MWh without cost verification is generally consistent with the current market structures in RTOs/ ISOs, which typically allow imports to offer up to the same offer cap that internal RTO/ISO resources are subject to. A similar logic applies to export transactions. 194. Further, prohibiting imports from offering above $1,000/MWh could result in uneconomic flows between RTOs/ ISOs. For example, if the LMP in one 428 PJM Market Monitor Comments at 11; PJM Market Monitor Answer at 2–3. 429 PJM Market Monitor Answer at 2. 430 PJM Market Monitor Comments at 11; PJM Market Monitor Answer at 3. 431 PJM Market Monitor Answer at 3. E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES4 RTO/ISO is $1,500/MWh and an external resource would like to offer an import at a price of $1,400/MWh, a prohibition on import offers above $1,000/MWh would restrict that transaction and result in inefficient flows across RTO/ISO boundaries. 195. Additionally, we will not require import offers above $1,000/MWh be cost-verified and find that imports are not similarly situated to internal generation resources. Unlike incremental energy offers from internal resources, import offers are often not resource-specific and, thus, it is difficult—some commenters say impossible—to ascertain the underlying costs of most import offers. This approach is consistent with current market power mitigation measures in RTOs/ISOs that apply to internal resources but do not typically apply to imports. 196. Additionally, RTO/ISO market participants can import energy from adjacent markets and sell that energy in the RTO/ISO energy market. Therefore, it is difficult for external resources in an adjacent market to withhold because internal RTO/ISO resources can import energy from that adjacent market. Additionally, provided the adjacent market is competitive, which is expected if the adjacent market is an RTO/ISO with market power mitigation, it would be difficult for an external resource to exercise market power in the importing RTO/ISO. 197. Though it is not required, the Commission would consider proposals by RTOs/ISOs to verify or otherwise review the costs of imports or exports and/or develop additional mitigation provisions for import and export transactions above $1,000/MWh. Such proposals should be submitted in a separate filing under section 205 of the Federal Power Act. 198. We clarify that this Final Rule will not apply to Coordinated Transactions Schedules, which are spread bids as opposed to energy offers. Additionally, the Final Rule will not apply to emergency purchases, which would go beyond the scope of this Final Rule because such transactions are administratively priced rather than based on short-run marginal cost. VI. Other Comments 199. The Commission also sought comment on various aspects of the verification process and the types of costs that should be considered in the verification. Specifically, the Commission sought comment on (1) whether the Market Monitoring Unit or RTOs/ISOs may need additional information to ensure that all short-run VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 marginal cost components that are difficult to quantify, such as certain opportunity costs, are accurately reflected in a resource’s cost-based incremental energy offer, and (2) to the extent that RTOs/ISOs currently include an adder above cost in cost-based incremental energy offers, whether such an adder is appropriate for incremental energy offers above $1,000/MWh.432 Commenters also discussed the impact that the proposed offer cap reforms could have on other market constructs, such as shortage pricing. A. Verification Requirement Details 1. Comments 200. Commenters express differing views on whether opportunity costs are legitimate costs, and if so, whether it is appropriate to include them within costbased incremental energy offers. The PJM Market Monitor states that it currently calculates opportunity costs at the request of PJM members and does not need additional information about the details of opportunity costs.433 The SPP Market Monitor explains that SPP currently allows an opportunity cost adder above mitigated offers, which would still be appropriate to include if costs exceed $1,000/MWh.434 201. Midcontinent Joint Consumer Advocates and TAPS oppose opportunity cost adders in the verification methodology for cost-based incremental energy offers above $1,000/ MWh.435 Midcontinent Joint Consumer Advocates add that if the Commission finds that opportunity costs may be recoverable, then the Market Monitoring Unit should review such costs to ensure they are just and reasonable.436 202. Commenters expressed a range of opinions regarding whether it is appropriate to account for cost uncertainty or other risks through an adder in cost-based incremental energy offers above $1,000/MWh. SPP takes no position on the appropriateness of the adder but argues that the different RTOs/ISOs should be allowed to develop verification rules that are consistent with their existing rules, including adders.437 PJM, MISO, the PJM Market Monitor, and Potomac 432 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 73. Market Monitor Comments at 8. 434 SPP Market Monitor Comments at 10. The SPP Market Monitor notes that resources can use forecasted LMPs and production costs to estimate price-cost margins for each hour of the day to determine the opportunity cost component of the mitigated offer. 435 Midcontinent Joint Consumer Advocates Comments at 6–7; TAPS Comments at 16. 436 Midcontinent Joint Consumer Advocates Comments at 6–7. 437 PJM/SPP Comments at 24. 433 PJM PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 87795 Economics support an adder of up to ten percent to account for uncertainty and risk.438 The ISO–NE Market Monitor states that the primary function of a ten percent adder is to provide for errors or under-estimation of a resource’s marginal cost and contends that the Commission should not require such an adder unless it identifies specific and valid costs that are unique to days with abnormally high natural gas prices.439 203. Dominion, Exelon, ODEC, and PJM support the inclusion of a ten percent adder to cost-based incremental offers.440 Dominion and Exelon contend that a ten percent adder to cost-based incremental offers is appropriate because the adder accounts for some of the uncertainty that accompanies fuel cost estimation as well as dispatch instructions.441 ODEC maintains that the ten percent adder in cost-based incremental energy offers is both justified and necessary in PJM and should not be removed because it accounts for the fact that some costs are unknown when PJM resources compute their cost-based incremental energy offers.442 APPA, NRECA, and AMP state that adders above cost are not necessary when a resource’s costs can be accurately verified prior to the market clearing process.443 204. However, the New Jersey Commission, Direct Energy, PG&E, TAPS, and Industrial Customers oppose including a ten percent adder in costbased incremental energy offers above $1,000/MWh.444 The New Jersey Commission argues that such an adder would simply afford the generators an additional ten percent margin of profit above their costs that consumers would fund.445 TAPS and Industrial Customers state that the ten percent adder should not be included in incremental energy offers above $1,000/MWh because the 438 Id. at 22–23; MISO Comments at 15; PJM Market Monitor Comments at 9; Potomac Economics Comments at 7. 439 ISO–NE Market Monitor Comments at 12 440 Dominion Comments at 6; Exelon Comments at 20 (citing Testimony of Kevin A. Libby at 8–9 (Libby Test.)); ODEC Comments at 5–6; PJM/SPP Comments at 22. 441 Dominion Comments at 6; Exelon Comments at 20 (citing Libby Test. at 8–9). 442 ODEC Comments at 6 (citing PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 30). 443 APPA, NRECA, and AMP Comments at 17. 444 Direct Energy Comments at 5; PG&E Comments at 3; New Jersey Commission Comments at 17; TAPS Comments at 16; Industrial Customers Comments at 25–26 (citing PJM Market Monitor Comments, Docket No. ER14–1144, at 2, n. 5 (filed Mar. 26, 2015)). 445 New Jersey Commission Comments at 17. E:\FR\FM\05DER4.SGM 05DER4 87796 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations sradovich on DSK3GMQ082PROD with RULES4 adder does not constitute an actual cost.446 205. With respect to other short-run marginal cost components, the Pennsylvania Commission, CAISO, and Industrial Customers argue that a resource’s permissible short-run marginal costs should not include unauthorized natural gas costs and natural gas pipeline penalties.447 CAISO requests that the Commission convene a technical conference to discuss limitations in fuel markets and the appropriate parameters for determining prudently incurred costs.448 Industrial Customers recount the Commission’s reasoning that allowing recovery for costs and penalties of unauthorized gas consumption could jeopardize gas pipeline and transmission system reliability, and that generators would still have sufficient flexibility.449 206. The Commission also sought comment on whether the verification of physical offer components is necessary.450 The ISO–NE Market Monitor states that ISO–NE’s existing process to verify physical offer components takes significant time because such changes to physical offer parameters cannot be completed on the day that offers are due.451 The ISO–NE Market Monitor advises the Commission to avoid imposing time limitations that interfere with the ISO–NE Market Monitor’s ability to review and verify physical parameters before-the-fact.452 The PJM Market Monitor requests that the Commission clarify that the costbased offers contemplated in the NOPR include the same limits on offer parameters as all other cost-based offers.453 Potomac Economics advises that any Final Rule not address physical parameters because additional verification of physical parameters is not needed, and the proposal only addressed incremental energy offers.454 Midcontinent Joint Consumer Advocates note that physical offer components such as generation minimum and maximum levels are 446 TAPS Comments at 16; Industrial Customers Comments at 25–26 (citing PJM Market Monitor Comments, Docket No. ER14–1144, at p. 2, n. 5 (filed Mar. 26, 2015)). 447 Pennsylvania Commission Comments at 5, 10; CAISO Comments at 11–12; Industrial Customers Comments at 26. 448 CAISO Comments at 12. 449 Industrial Customers Comments at 26–27 (citing N.Y. Indep. Sys. Operator, Inc., 154 FERC ¶ 61,111, at P 1 (2016)). 450 NOPR, FERC Stats. & Regs. ¶ 32,714 at P 73. 451 ISO–NE Market Monitor Comments at 10. 452 Id. at 11. 453 PJM Market Monitor Comments at 2–3. 454 Potomac Economics Comments at 11 (citing Potomac Economics Post-Technical Workshop Comments. Docket No. AD14–14–000, at 5 (filed Feb. 24, 2015)). VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 already known and reviewed by the Market Monitoring Unit, and therefore, there is no need for additional verification of physical offer components.455 2. Determination 207. Several commenters state that adders above costs should be included in cost-based offers to account for cost uncertainty or risk.456 While we will not require RTOs/ISOs to include such an adder, if an RTO/ISO chooses to retain an adder above cost or proposes to include a new adder above cost in costbased incremental energy offers above $1,000/MWh, such adders may not exceed $100/MWh. On balance, we find that limiting adders above cost to $100/ MWh is just and reasonable because as clarified above, the verification process may involve reviewing a resource’s expected, rather than actual, costs, which could involve the use of imperfect information. Given that practical reality, we find that it is necessary to place an upper bound on the level of adders above cost when incremental energy offers exceed $1,000/MWh in order to ensure that cost-based incremental energy offers above $1,000/MWh reasonably and accurately reflect actual or expected short-run marginal cost.457 The Commission has previously found in PJM that adders above cost are unjust and unreasonable as applied to an afterthe-fact review of documented costs because the costs are no longer uncertain.458 Applying that same reasoning here, if a resource receives uplift after-the-fact because that resource’s cost-based incremental energy offer above $1,000/MWh could not be verified prior to the market clearing process or because its costbased incremental energy offer exceeded $2,000/MWh, the uplift payments that the resource receives should not include any adders above costs. As noted above, after-the-fact uplift would be based on a resource’s actual costs.459 208. Based on the record before us, we will not require that additional information on short-run marginal cost components be provided to the RTO/ 455 Midcontinent Joint Consumer Advocates Comments at 6. 456 See supra P 203. 457 The Commission notes that it previously accepted adders above costs in PJM that exceed $100/MWh. However, after reviewing the record before us in this proceeding, we find that it is just and reasonable to limit the adder to $100/MWh. See PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 31. 458 PJM 2015 Offer Cap Order, 153 FERC ¶ 61,289 at P 31 (citing PJM Interconnection, L.L.C., 149 FERC ¶ 61,059 at P 13). 459 See supra P 146. PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 ISO or Market Monitoring Unit. Furthermore, we will not prescribe the manner in which RTOs/ISOs or Market Monitoring Units verify cost-based incremental energy offers above $1,000/ MWh. As indicated in the NOPR, RTOs/ ISOs use different processes to develop and update the incremental energy offers used for mitigation and differ in how they define the components of costbased incremental energy offers.460 While we are taking no action at this time on these issues and comments, we do not prejudge what RTOs/ISOs may file with the Commission in the future. Accordingly, the Final Rule will not require verification of physical offer parameters or financial offer components other than the incremental energy offer. B. Impact of Offer Cap Reforms on Other Market Elements 209. The Commission recognized in the NOPR that revising the offer cap may impact other RTO/ISO market elements that depend on the offer cap, such as shortage pricing levels or various penalty factors.461 1. Comments 210. Four RTOs/ISOs commented that RTO/ISO market elements other than the offer cap may need to be revised if the offer cap is revised. CAISO states that it will face significant implementation challenges if it changes its current $1,000/MWh offer cap because the administrative penalty prices CAISO uses in its market model to indicate that constraints have been relaxed, such as the power balance constraint, are based on the offer cap.462 211. PJM states that it would likely need to adjust shortage pricing rules in PJM in light of any Final Rule on offer caps.463 SPP states that it would likely need to revise its scarcity prices and violation relaxation limits to prevent instances in which LMPs exceed scarcity values.464 MISO states that it may need to revise its Operating Reserve Demand Curve, $3,500/MWh LMP cap, and Transmission Constraint Demand Curves if MISO’s $1,000/MWh offer cap is revised.465 212. APPA, NRECA, and AMP and ODEC state that any Final Rule 460 NOPR, FERC Stats. & Regs. ¶ 32,714 at PP 61– 62. 461 Id. P 72. Comments at 14–17. CAISO requests that, prior to issuing the Final Rule, the Commission conduct a technical conference to better understand the challenges of implementation. CAISO Comments at 3, 17. 463 PJM/SPP Comments at 28. 464 Id. at 29. 465 MISO Comments at 3–5. 462 CAISO E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations regarding offer caps should be restricted to changing the offer cap and not address potentially associated issues such as scarcity pricing.466 In contrast, PG&E recommends that before allowing the offer cap to rise above $1,000/MWh, the Commission and the individual RTOs/ISOs should determine all related changes to the markets that would be needed to ensure that the markets would function properly.467 2. Determination 213. An RTO/ISO may file, pursuant to section 205 of the Federal Power Act, to propose modifications to shortage prices or other market elements that require revision in light of the offer cap reforms adopted in this Final Rule. However, we do not require such modifications to comply with this Final Rule. We find that it is not appropriate to determine in this Final Rule the changes that individual RTOs/ISOs should make to market elements that are not the subject of these reforms. sradovich on DSK3GMQ082PROD with RULES4 VII. Requests Beyond the Scope of This Proceeding A. Comments 214. Commenters raised issues that are not discussed above and that are outside the scope of this rulemaking. Several commenters argue that the focus of the recommendations in the NOPR is too narrow. API recommends that the Commission look for ways to encourage the appropriate integration of new technologies, including quickly ramping gas-fired generation technology, to meet rapidly changing grid-conditions and allow prices in real-time markets to better reflect the true state of grid reliability at a given moment while addressing any remaining concerns of market power abuse.468 API further recommends that the Commission initiate an examination of opportunity costs and risk premiums, inclusive of a wider range of resources, in wholesale energy market offer pricing and how they may or may not be considered by various RTO/ISO market rules.469 215. The PJM Market Monitor argues that because gas is the only fuel likely to result in offers greater than $1,000/ MWh, the removal of any cap on short run marginal cost therefore relies on the competitiveness of the gas markets.470 The PJM Market Monitor suggests that a reconsideration of the structure and design of the gas market and the potential for a gas market RTO/ISO is a longer term solution to address issues of transparency and market power in the gas market.471 216. The Pennsylvania Commission states that the Commission should direct PJM and other RTO/ISO stakeholders to develop a ‘‘circuit breaker’’ provision to cap energy market revenue during uncontrollable and sustained outage events.472 The Pennsylvania Commission states that during sustained outages, price signals in energy markets become irrelevant, and the main consideration is the time required to repair infrastructure as opposed to the economic theory behind energy markets.473 The Pennsylvania Commission also recommends that the Commission direct PJM to introduce some level of aggregate market power mitigation or impose a screen for aggregate market power in the PJM dayahead and real-time markets.474 PJM Joint Consumer Advocates argue that shortage prices in PJM should be revised to represent customers’ willingness to pay,475 and the Ohio Commission states that scarcity pricing may no longer be necessary in light of this Final Rule.476 217. Industrial Customers argue that increases to the current $1,000/MWh offer cap should be explored simultaneously with the elimination of capacity markets, and that the Commission could act more methodically to explore ways to improve capacity market competitiveness and transparency.477 B. Determination 218. We appreciate the concerns raised by numerous commenters requesting that the Commission undertake various initiatives, as set forth above. However, we find that the requested initiatives go beyond the scope of this rulemaking, which only addresses incremental energy offers above $1,000/MWh. Accordingly, we will not address those concerns here. VIII. Information Collection Statement 219. The Paperwork Reduction Act (PRA) 478 requires each federal agency to seek and obtain Office of Management and Budget (OMB) approval before undertaking a collection of information directed to ten or more persons or contained in a rule of general 471 Id. at 6. 472 Pennsylvania Commission Comments at 5–7. at 8. 474 Id. at 13–14. 475 PJM Joint Consumer Advocates Comments at 5–6. 476 Ohio Commission Comments at 14–15. 477 Industrial Customers Comments at 29–30. 478 44 U.S.C. 3501–3520. 473 Id. 466 ODEC Comments at 1; APPA, NRECA, and AMP Comments at 20–21. 467 PG&E Comments at 2. 468 API Comments at 2–3. 469 Id. at 8. 470 PJM Market Monitor Comments at 4. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 87797 applicability. OMB’s regulations,479 in turn, require approval of certain information collection requirements imposed by agency rules. Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a rule will not be penalized for failing to respond to these collection(s) of information unless the collection(s) of information display a valid OMB control number. 220. In this Final Rule, we are amending the Commission’s regulations to improve the operation of organized wholesale electric power markets operated by RTOs/ISOs. We require that each RTO/ISO (1) cap each resource’s incremental energy offer at the higher of $1,000/MWh or that resource’s verified cost-based incremental energy offer; and (2) when calculating LMPs, RTOs/ISOs shall cap verified cost-based incremental energy offers at $2,000/ MWh. The reforms required in this Final Rule would require a one-time tariff filing with the Commission due 75 days after the effective date of this Final Rule to implement these reforms. We anticipate the reforms required in this Final Rule, once implemented, would not significantly change currently existing burdens on an ongoing basis. With regard to those RTOs/ISOs that believe that they already comply with the reforms required in this Final Rule, they could demonstrate their compliance in the compliance filing required 75 days after the effective date of this Final Rule in this proceeding. The Commission will submit the proposed reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.480 221. In the NOPR, the Commission sought comments on the accuracy of provided burden and cost estimates and any suggested methods for minimizing the respondents’ burdens, including the use of automated information techniques. Specifically, the Commission sought detailed comments on the potential cost and time necessary to implement aspects of the reforms proposed in the NOPR, including (1) software and business processes changes, including market power mitigation; (2) increased time spent validating cost-based incremental energy offers; and (3) processes for RTOs/ISOs to vet proposed changes amongst their stakeholders. The Commission also stated that although it did not expect other entities to incur 479 5 CFR 1320 (2016). U.S.C. 3507(d). 480 44 E:\FR\FM\05DER4.SGM 05DER4 87798 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations compliance costs as a result of the reforms proposed in the NOPR, it sought detailed comments on whether other entities, such as load-serving entities, would incur costs as a result of the reforms proposed in the NOPR. The Commission received no comments in response to these questions. Burden Estimate and Information Collection Costs: The Commission believes that the burden estimates below are representative of the average burden on respondents, including necessary communications with stakeholders. The estimated burden and cost for the requirements contained in this rule follow.481 The Commission notes that these cost estimates below do not include costs for software or hardware or for increased time spent validating cost-based incremental energy offers above $1,000/MWh.482 Software or hardware upgrades may not be required. FERC–516, AS MODIFIED BY FINAL RULE IN DOCKET RM16–5–000 Number of respondents Annual number of responses per respondent Total number of responses Average burden (hours) & cost per response Total annual burden hours & total annual cost Cost per respondent ($) (1) (2) (1) × (2) = (3) (4) (3) × (4) = (5) (5) ÷ (1) 6 1 6 One-Time Tariff Filings (Year 1). 500 hrs.; $37,000 483 3,000 hrs.; $222,000 $37,000 sradovich on DSK3GMQ082PROD with RULES4 Cost to Comply: The Commission has projected the total cost of compliance, all within four months of a Final Rule plus initial implementation, to be $222,000. After Year 1, the reforms in this Final Rule, once implemented, would not significantly change existing burdens on an ongoing basis. The Commission notes that these estimates do not include costs for software or hardware. Software or hardware upgrades may not be required. Title: FERC–516C,484 Electric Rate Schedules and Tariff Filings. Action: Proposed revisions to an information collection. OMB Control No. 1902–0287. Respondents for this Rulemaking: RTOs/ISOs. Frequency of Information: One-time. Necessity of Information: The Federal Energy Regulatory Commission approves this rule to improve competitive wholesale electric markets in the RTO/ISO regions. Internal Review: The Commission has reviewed the changes and has determined that such changes are necessary. These requirements conform to the Commission’s need for efficient information collection, communication, and management within the energy industry. The Commission has specific, objective support for the burden estimates associated with the information collection requirements. 222. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], email: DataClearance@ferc.gov, Phone: (202) 502–8663, fax: (202) 273–0873. Comments concerning the collection of information and the associated burden estimate(s), may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395–0710, fax (202) 395–7285]. Due to security concerns, comments should be sent electronically to the following email address: oira_submission@ omb.eop.gov. Comments submitted to OMB should include FERC–516C and OMB Control No. 1902–0287. 481 The RTOs/ISOs (CAISO, ISO–NE., MISO, NYISO, PJM, and SPP) are required to comply with the reforms in this Final Rule. 482 The Commission expects that the validation of cost-based incremental energy offers above $1,000/ MWh would be an infrequent occurrence. To the extent that the Market Monitoring Unit or the RTO/ ISO spends time validating these offers, the Commission estimates such time to be de minimis. 483 The estimated hourly cost (salary plus benefits) provided in this section is based on the salary figures for May 2015 posted by the Bureau of Labor Statistics for the Utilities sector (available at http://www.bls.gov/oes/current/naics2_ 22.htm#13-0000) and scaled to reflect benefits using the relative importance of employer costs in employee compensation from June 2016 (available at http://www.bls.gov/news.release/ecec.nr0.htm). The hourly estimates for salary plus benefits are: Legal (code 23–0000), $128.94 Computer and mathematical (code 15–0000), $60.54 Information systems manager (code 11–3021), $91.63 IT security analyst (code 15–1122), $63.55 Auditing and accounting (code 13–2011), $53.78 Information and record clerk (code 43–4199), $37.69 Electrical Engineer (code 17–2071), $64.20 Economist (code 19–3011), $74.43 Management (code 11–0000), $88.94 The average hourly cost (salary plus benefits), weighting all of these skill sets evenly, is $73.74. The Commission rounds it to $74 per hour. 484 The RM16–5–000 Final Rule reporting requirements should be submitted to FERC–516 (OMB Control No. 1902–0096). Currently, that information collection is under review for an unrelated activity. The FERC–516C is a temporary information collection. The reporting requirements of the RM16–5–000 Final Rule are being submitted to FERC–516C to ensure timely submission to OMB. 485 5 U.S.C. 601–12. 486 This estimate does not include costs for software or increased time spent validating costbased incremental energy offers. As stated above, the Commission expects that the validation of costbased incremental energy offers above $1,000/MWh would be an infrequent occurrence. To the extent that the Market Monitoring Unit or the RTO/ISO spends time validating these offers, the Commission expects such time to be de minimis. 487 The RFA definition of ‘‘small entity’’ refers to the definition provided in the Small Business Act, which defines a ‘‘small business concern’’ as a business that is independently owned and operated and that is not dominant in its field of operation. The Small Business Administrations’ regulations at 13 CFR 121.201 define the threshold for a small Electric Bulk Power Transmission and Control VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 IX. Regulatory Flexibility Act Certification 223. The Regulatory Flexibility Act of 1980 (RFA) 485 generally requires a description and analysis of rules that will have significant economic impact on a substantial number of small entities. The RFA does not mandate any particular outcome in a rulemaking. It only requires consideration of alternatives that are less burdensome to small entities and an agency explanation of why alternatives were rejected. 224. This rule would apply to six RTOs/ISOs (all of which are transmission organizations). The average estimated annual cost to each of the RTOs/ISOs is $37,000, all in Year 1. This one-time cost of filing and implementing these changes is not significant.486 Additionally, the RTOs/ ISOs are not small entities, as defined by the RFA.487 This is because the E:\FR\FM\05DER4.SGM 05DER4 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations relevant threshold between small and large entities is 500 employees and the Commission understands that each RTO/ISO has more than 500 employees. Furthermore, because of their pivotal roles in wholesale electric power markets in their regions, none of the RTOs/ISOs meet the last criterion of the two-part RFA definition a small entity: ‘‘not dominant in its field of operation.’’ As a result, we certify that the reforms in this Final Rule would not have a significant economic impact on a substantial number of small entities. X. Environmental Analysis 225. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.488 The Commission concludes that neither an Environmental Assessment nor an Environmental Impact Statement is required for this Final Rule under section 380.4(a)(15) of the Commission’s regulations, which provides a categorical exemption for approval of actions under sections 205 and 206 of the Federal Power Act relating to the filing of schedules containing all rates and charges for the transmission or sale of electric energy subject to the Commission’s jurisdiction, plus the classification, practices, contracts and regulations that affect rates, charges, classifications, and services.489 XI. Document Availability 226. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission’s Home Page (http:// www.ferc.gov) and in the Commission’s Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426. 227. From the Commission’s Home Page on the Internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number of this document, excluding the last three digits, in the docket number field. 228. User assistance is available for eLibrary and the Commission’s Web site during normal business hours from the Commission’s Online Support at 202– 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502–8371, TTY (202) 502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. XII. Effective Date and Congressional Notification 229. These regulations are effective February 21, 2017. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a ‘‘major rule’’ as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996. List of Subjects in 18 CFR Part 35 Electric power rates, Electric utilities, Non-discriminatory open access transmission tariffs. By the Commission. Issued: November 17, 2016. Nathaniel J. Davis, Sr., Deputy Secretary. In consideration of the foregoing, the Commission amends part 35, chapter I, title 18, Code of Federal Regulations, as follows: 87799 PART 35—FILING OF RATE SCHEDULES AND TARIFFS 1. The authority citation for part 35 continues to read as follows: ■ Authority: 16 U.S.C. 791a–825r, 2601– 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352. 2. Amend § 35.28 by adding paragraph (g)(9) to read as follows: ■ § 35.28 Non-discriminatory open access transmission tariff. * * * * * (g) * * * (9) A resource’s incremental energy offer must be capped at the higher of $1,000/MWh or that resource’s costbased 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. 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-thefact. 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. All resources, regardless of type, are eligible to submit cost-based incremental energy offers in excess of $1,000/MWh. The following appendix will not appear in the Code of Federal Regulations. APPENDIX—LIST OF SHORT NAMES/ACRONYMS OF COMMENTERS Commenter AEMA .............................................. AF&PA ............................................ APPA, NRECA, and AMP ............... sradovich on DSK3GMQ082PROD with RULES4 Short name/acronym Advanced Energy Management Alliance. American Forest & Paper Association. American Public Power Association, National Rural Electric Cooperative Association and American Municipal Power, Inc. American Petroleum Institute. California Independent System Operator Corporation. Canadian Electricity Association. Electric Power Supply Association, Independent Energy Producers Association, Independent Power Producers of New York Inc., New England Power Generators Association Inc., Western Power Trading Forum. Delaware Public Service Commission. API .................................................. CAISO ............................................. CEA ................................................. Competitive Suppliers ..................... Delaware Commission .................... entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 632. VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 488 Regulations Implementing the National Environmental Policy Act of 1989, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 489 18 E:\FR\FM\05DER4.SGM CFR 380.4(a)(15) (2016). 05DER4 87800 Federal Register / Vol. 81, No. 233 / Monday, December 5, 2016 / Rules and Regulations APPENDIX—LIST OF SHORT NAMES/ACRONYMS OF COMMENTERS—Continued Short name/acronym Commenter Direct Energy .................................. Dominion ......................................... EEI .................................................. Exelon ............................................. Golden Spread ................................ Industrial Customers ....................... Direct Energy Business, LLC, on behalf of itself and its affiliate, Direct Energy Business Marketing, LLC. Dominion Resources Services, Inc. Edison Electric Institute. Exelon Corporation. Golden Spread Electric Cooperative, Inc. Electricity Consumers Resource Council, PJM Industrial Customer Coalition, Coalition of MISO Transmission Customers, American Chemistry Council, Association of Businesses Advocating Tariff Equity, Connecticut Industrial Energy Consumers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Louisiana Energy Users Group, Minnesota Large Industrial Group, Missouri Industrial Energy Consumers, Multiple Intervenors, New Jersey Large Energy Users Coalition, Wisconsin Industrial Energy Group, Inc. Industrial Energy Consumers of America. ISO New England, Inc. ISO New England Inc. Internal Market Monitor. ISO/RTO Council. Kansas Electric Power Cooperative, Inc. and North Carolina Electric Membership Corporation. Joseph Margolies. Indiana Office of Utility Consumer Counselor, Iowa Office of Consumer Advocate, Michigan Citizens Against Rate Excess, Minnesota Department of Commerce, Minnesota Attorney General’s Office. Midcontinent Independent System Operator, Inc. Nuclear Energy Institute. New England States Committee on Electricity. New Jersey Board of Public Utilities. New York State Department of State Utility Intervention Unit. New York Independent System Operator, Inc. New York State Public Service Commission. New York Transmission Owners (Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc., New York Power Authority, New York State Electric & Gas Corporation, Niagara Mohawk Power Corporation d/b/a National Grid, Orange and Rockland Utilities, Inc., Power Supply Long Island, Rochester Gas and Electric Corporation). Old Dominion Electric Cooperative. Organization of MISO States. Organization of PJM States, Inc. Pennsylvania Public Utility Commission. Pacific Gas and Electric Company. PJM Interconnection, L.L.C. and Southwest Power Pool, Inc. (Joint Comments). Delaware Division of the Public Advocate, Office of People’s Counsel for the District of Columbia, Illinois Citizens Utility Board, Indiana Office of Utility Consumer Counselor, Kentucky Office of Rate Intervention, Office of Attorney General, Maryland Office of Peoples’ Counsel, New Jersey Division of Rate Counsel, Pennsylvania Office of Consumer Advocate, Consumer Advocate Division of the Public Service Commission of West Virginia. Monitoring Analytics, LLC, acting in its capacity as the Independent Market Monitor for PJM. PJM Power Providers Group. Potomac Economics, Ltd. Powerex Corp. Public Utilities Commission of Ohio. Southern California Edison Company. Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California. Southwest Power Pool, Inc. Southwest Power Pool, Inc. Market Monitoring Unit. Steel Producers’ Alliance. Transmission Access Policy Study Group. Industrial Energy Consumers ......... ISO–NE ........................................... ISO–NE Market Monitor .................. IRC .................................................. KEPCo/NCEMC .............................. Joseph Margolies ............................ Midcontinent Joint Consumer Advocates. MISO ............................................... NEI .................................................. NESCOE ......................................... New Jersey Commission ................ NY Department of State ................. NYISO ............................................. New York Commission ................... NY Transmission Owners ............... ODEC .............................................. OMS ................................................ OPSI ................................................ Pennsylvania Commission .............. PG&E .............................................. PJM/SPP ......................................... PJM Joint Consumer Advocates .... PJM Market Monitor ........................ PJM Power Providers ..................... Potomac Economics ....................... Powerex .......................................... Ohio Commission ............................ SCE ................................................. Six Cities ......................................... SPP ................................................. SPP Market Monitor ........................ Steel Producers’ Alliance ................ TAPS ............................................... [FR Doc. 2016–28320 Filed 12–2–16; 8:45 am] sradovich on DSK3GMQ082PROD with RULES4 BILLING CODE 6717–01–P VerDate Sep<11>2014 19:31 Dec 02, 2016 Jkt 214001 PO 00000 Frm 00032 Fmt 4701 Sfmt 9990 E:\FR\FM\05DER4.SGM 05DER4

Agencies

[Federal Register Volume 81, Number 233 (Monday, December 5, 2016)]
[Rules and Regulations]
[Pages 87770-87800]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-28320]



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Vol. 81

Monday,

No. 233

December 5, 2016

Part IV





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Part 35





Offer Caps in Markets Operated by Regional Transmission Organizations 
and Independent System Operators; Final Rule

Federal Register / Vol. 81 , No. 233 / Monday, December 5, 2016 / 
Rules and Regulations

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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.

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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              16
         That Current Offer Caps are Unjust and
         Unreasonable......................................
        2. Comments that Oppose Reforming Current Offer               20
         Caps..............................................
        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

[[Page 87771]]

 
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.
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    \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.
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    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.

[[Page 87772]]

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

[[Page 87773]]

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

[[Page 87774]]

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

[[Page 87775]]

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

[[Page 87776]]

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

[[Page 87777]]

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

[[Page 87778]]

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

[[Page 87779]]

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

[[Page 87780]]

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

[[Page 87781]]

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

[[Page 87782]]

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.

---------------------------------------------------------------------------

[[Page 87783]]

    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

[[Page 87784]]

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

[[Page 87785]]

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

[[Page 87786]]

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 cleared energy should instead be compensated at the 
LMP.\273\ PJM Power Providers and Competitive Suppliers assert that 
even after-the-fact verification of a resource's costs will be 
challenging, and, according to Competitive Suppliers, it will be 
particularly challenging for natural gas resources that have complex 
fuel supply arrangements.\274\
---------------------------------------------------------------------------

    \270\ Competitive Suppliers Comments at 19; MISO Comments at 10; 
PG&E Comments at 3; PJM Power Providers Comments at 4.
    \271\ MISO Comments at 10.
    \272\ PG&E Comments at 3.
    \273\ Id.
    \274\ Competitive Suppliers Comments at 19; PJM Power Providers 
Comments at 4.
---------------------------------------------------------------------------

    120. Competitive Suppliers state that in some instances, a resource 
may not be able to use the RTO's/ISO's verification process to set the 
market clearing price (for offers above $1,000/MWh) and in such rare 
cases, it may be necessary to compensate that resource through an 
uplift payment based on after-the-fact cost verification.\275\ 
Competitive Suppliers assert that if a resource incurs justifiable and 
demonstrable short-run marginal costs, those costs should be recovered 
so that the resource does not operate at a loss and so that the 
resource is not discouraged from offering supply to the market.\276\
---------------------------------------------------------------------------

    \275\ Competitive Suppliers Comments at 20-21.
    \276\ Id. at 21.
---------------------------------------------------------------------------

    121. NEI states that, given that the Commission's price formation 
reforms are aimed at reducing the use of out-of-market payments, NEI is 
disappointed by the NOPR proposal to include uplift payments as a fall 
back if before-the-fact cost verification proves infeasible in 
practice.\277\ However, Direct Energy states that if a resource's 
verified cost-based incremental energy offer exceeds the cap, that 
resource should be entitled to full cost recovery of RTO/ISO approved 
costs through uplift.\278\
---------------------------------------------------------------------------

    \277\ NEI Comments at 4.
    \278\ Direct Energy Comments at 3.
---------------------------------------------------------------------------

e. Specific Proposals for the Verification Requirement
    122. Given the concerns about verification of actual costs, several 
commenters, including RTOs/ISOs,\279\ Market Monitoring Units,\280\ and 
other stakeholders,\281\ request that the Commission clarify that if it 
is not possible to verify a resource's actual costs prior to setting 
LMP, it will accept a process that verifies that a resource's 
incremental energy offer reasonably reflects that resource's expected 
costs.
---------------------------------------------------------------------------

    \279\ ISO-NE Comments at 4-7; NYISO Comments at 2; PJM/SPP 
Comments at 12-13.
    \280\ Potomac Economics Comments at 3-4; ISO-NE Market Monitor 
Comments at 4.
    \281\ EEI Comments at 6-7; Exelon Comments at 17.
---------------------------------------------------------------------------

    123. Several commenters maintain that a prior-to-the-market-
clearing verification process that requires cost-based offers be equal 
to actual costs will likely result in fewer incremental energy offers 
above $1,000/MWh that are eligible to set LMP.\282\ For example, EEI 
states that its primary concern with the NOPR is the verification 
process and whether it is workable.\283\ The ISO-NE Market Monitor and 
PJM/SPP state that there is a trade-off between the level of precision 
of the cost-based offer verification, the number of offers that will be 
eligible to set LMPs, and the level of uplift.\284\
---------------------------------------------------------------------------

    \282\ CEA Comments at 5; EEI Comments at 5.
    \283\ EEI Comments at 5.
    \284\ ISO-NE Market Monitor Comments at 5; PJM/SPP Comments at 
13.
---------------------------------------------------------------------------

    124. Several commenters ask the Commission to indicate the types of 
verification processes it would accept.\285\ ISO-NE., MISO, and NYISO 
state that their current process for developing and updating cost-based 
incremental energy offers, known as reference levels, could comply with 
the proposal as clarified to include estimated costs.\286\
---------------------------------------------------------------------------

    \285\ CEA Comments at 6; IRC Comments at 2.
    \286\ ISO-NE Comments at 6; MISO Comments at 8; NYISO Comments 
at 2.
---------------------------------------------------------------------------

    125. CAISO states that the simplest method of verifying cost-based 
incremental energy offers would involve reviewing a broker quote or 
procurement invoice provided as evidence of a resource's costs, but 
CAISO questions whether such information would be sufficient.\287\ 
CAISO predicts that incremental energy offers above $1,000/MWh are not 
likely to be eligible to set the clearing price in CAISO and that 
instead a resource with costs above $1,000/MWh would receive an uplift 
payment, assuming that the resource's costs were verified after-the-
fact.\288\
---------------------------------------------------------------------------

    \287\ CAISO Comments at 11.
    \288\ Id.
---------------------------------------------------------------------------

    126. PJM/SPP state that the principles outlined in the NOPR are 
sound, provided that the Final Rule allows RTOs/ISOs flexibility to 
design verification procedures that are consistent with current RTO/ISO 
rules.\289\ PJM/SPP outline conceptual initial proposals for 
verification, but stress the need to provide RTOs/ISOs with latitude to 
develop the final verification process with stakeholders.\290\ PJM 
presents a possible verification process that involves an automatic 
screen to filter out unreasonably high offers and to create a range of 
reasonableness based on an

[[Page 87787]]

index of natural gas prices, the bid/ask spread, and resource heat 
rates.\291\ PJM states that the verification requirement could use a 
screening process that determines whether certain resources' 
incremental energy offers in a given area are within ten percent or 
$100/MWh of a benchmark offer based on a natural gas price index.\292\ 
SPP states that it could develop additional rules that facilitate 
resources' submission of the fuel cost component of their cost-based 
incremental energy offers that is consistent with the resource's actual 
costs where possible, or that is a reasonably accurate representation 
of those costs. SPP states that given the need to approximate fuel 
costs that are difficult to verify, in most cases such a verification 
process could be subject to a reasonable margin of error.\293\
---------------------------------------------------------------------------

    \289\ PJM/SPP Comments at 2-3.
    \290\ Id. at 14-21.
    \291\ Id. at 15-16.
    \292\ Id. at 16-17.
    \293\ Id. at 19.
---------------------------------------------------------------------------

    127. ISO-NE states that if its current cost verification process is 
acceptable to the Commission, then the offer cap proposal may be 
workable and would help improve price formation if high fuel prices 
cause generation costs to exceed $1,000/MWh.\294\ MISO contends that 
its current process to establish and adjust cost-based offers can be 
used to verify incremental energy offers above $1,000/MWh.\295\ NYISO 
also states that its current review process of a resource's incremental 
energy costs could be used to satisfy the proposed verification 
requirement.\296\
---------------------------------------------------------------------------

    \294\ ISO-NE Comments at 6.
    \295\ MISO Comments at 8.
    \296\ NYISO Comments at 3.
---------------------------------------------------------------------------

    128. The ISO-NE Market Monitor states that the Commission should 
revise the proposed verification requirement to permit use of ISO-NE's 
current Commission-approved process where a resource can update its 
cost-based incremental energy offer, which occurs through a ``Fuel 
Price Adjustment.'' \297\ The ISO-NE Market Monitor states that ISO-
NE's Fuel Price Adjustment mechanism balances the desire to reflect 
resource costs in cost-based incremental energy offers, the limited 
information the ISO-NE Market Monitor has available to verify costs, 
and the need to deter abuse.\298\ The ISO-NE Market Monitor explains 
that ISO-NE's market power mitigation software automatically calculates 
cost-based incremental energy offers for resources, which may be based 
on a day-ahead fuel price index.\299\
---------------------------------------------------------------------------

    \297\ ISO-NE Market Monitor Comments at 5-10.
    \298\ Id. at 5.
    \299\ Id. at 6.
---------------------------------------------------------------------------

    129. Potomac Economics states that MISO's current process for 
developing and updating reference levels would comply with a Final Rule 
which clarified that before-the-fact verification of a resource's 
expected costs is acceptable.\300\ Potomac Economics explains that in 
MISO, cost-based offers are calculated on the day before every 
operating day based on next-day fuel price indices.\301\ In real-time, 
the MISO Market Monitor (i.e., Potomac Economics), reviews natural gas 
prices on ICE at various delivery points, and if natural gas prices 
rise significantly compared to the next-day fuel index, the MISO Market 
Monitor adjusts the cost-based incremental energy offers of any 
affected resources.\302\ Potomac Economics adds that a MISO resource 
can also consult with the Market Monitor and request to raise its cost-
based offer beyond this adjustment if the resource provides supporting 
information, which may or may not be approved.\303\
---------------------------------------------------------------------------

    \300\ Potomac Economics Comments at 5.
    \301\ Id. at 4.
    \302\ Id. In MISO, cost-based offers are referred to as 
reference levels.
    \303\ Id. at 5.
---------------------------------------------------------------------------

    130. Potomac Economics explains that a NYISO resource may also 
request to update its cost-based incremental energy offer through a 
software process that automatically permits such an increase, provided 
the increase does not exceed a predetermined threshold.\304\ Potomac 
Economics maintains that NYISO may need to adjust the validation 
threshold to account for periods of unusually high fuel price 
volatility, but that with such an adjustment, NYISO's current 
verification process could comply with the proposal.\305\
---------------------------------------------------------------------------

    \304\ Id. NYISO states that a resource that updates the fuel 
type or fuel cost information associated with its cost-based 
incremental energy offer must make supporting documentation 
available for NYISO's review after-the-fact. See NYISO Comments at 
4.
    \305\ Potomac Economics Comments at 6.
---------------------------------------------------------------------------

    131. The PJM Market Monitor explains that resource owners in PJM 
are responsible for submitting their own cost-based offers and fuel 
cost policies, and that fuel costs are an essential part of the 
verification process.\306\ The PJM Market Monitor states that it does 
not have the authority to tell a resource owner what its fuel cost is 
or what its offer should be, but it does have the authority to verify 
cost-based offers, to discuss cost issues with resource owners, and to 
refer resource owners to the Commission for rule violations and for the 
attempted or actual exercise of market power.\307\ It states that it is 
essential that the Commission impose significant penalties for rule 
violations determined during the after-the-fact review. According to 
the PJM Market Monitor, a resource should be required to have in place 
a fuel cost policy that has been approved by both the PJM Market 
Monitor and PJM before the resource is able to submit an offer in 
excess of $1,000/MWh.\308\ The PJM Market Monitor states that if a 
resource's cost-based incremental energy offer above $1,000/MWh is used 
in the market clearing process, the PJM Market Monitor would perform a 
timely after-the-fact review to determine whether a resource's offer 
was based upon the best information available at the time the resource 
submitted the cost-based incremental energy offer.\309\ The PJM Market 
Monitor states that, in cases where an offer above $1,000/MWh is not 
permitted, the PJM Market Monitor would perform a timely after-the-fact 
review to determine the actual incurred costs of a resource, and uplift 
would be paid if the costs exceeded the market clearing price.\310\ Any 
uplift payments for such offers would be based on the actual gas cost 
incurred. The PJM Market Monitor also recommends that the $1,000/MWh 
offer cap apply to a resource's ``operating rate,'' which is calculated 
by adding a resource's incremental offer to its no-load offer.\311\
---------------------------------------------------------------------------

    \306\ PJM Market Monitor Comments at 4-5.
    \307\ Id. at 5.
    \308\ Id. at 6.
    \309\ Id. at 7-8.
    \310\ Id.
    \311\ Id. at 2.
---------------------------------------------------------------------------

    132. The PJM Market Monitor also maintains that it is essential 
that any verification process include a rigorous and timely after-the-
fact review and a requirement that a resource follows the cost-based 
offer submission rules and abides by its approved fuel cost policy. The 
PJM Market Monitor states that the verification process requires strong 
compliance incentives, and the Commission should impose significant 
penalties if a resource violates the cost-based incremental energy 
offer guidelines.\312\
---------------------------------------------------------------------------

    \312\ Id. at 7.
---------------------------------------------------------------------------

    133. Commenters representing generator and load interests also 
proposed verification processes. Competitive Suppliers and NEI state 
that lifting the offer cap to a level that does not artificially 
constrain LMPs is preferable to developing a verification process, as 
removing the cap allows the market price to convey accurate information 
of the state of the system even during high stress.\313\
---------------------------------------------------------------------------

    \313\ Competitive Suppliers Comments at 18; NEI Comments at 4.

---------------------------------------------------------------------------

[[Page 87788]]

    134. Competitive Suppliers prefer no verification requirement but 
contends that if the Commission requires that all cost-based 
incremental energy offers above $1,000/MWh be verified, the RTO/ISO and 
the generator should be able to identify a set of accepted criteria and 
data inputs such that resources can submit offers that can be accepted 
and thus eligible to set LMP.\314\ Competitive Suppliers state that 
PJM's Cost Development Guidelines provide a means of verifying resource 
costs and may provide an alternative approach to the proposed 
verification requirement.\315\
---------------------------------------------------------------------------

    \314\ Competitive Suppliers Comments at 19.
    \315\ Id.
---------------------------------------------------------------------------

    135. Exelon proposes that the Commission require RTOs/ISOs to adopt 
tariff provisions that will permit timely review and approval of 
resources' cost-based offers based on a resource-specific ``safe 
harbor'' formula that is agreed upon in advance.\316\ Exelon proposes 
that, at a minimum, the safe harbor formula should include a ten 
percent uncertainty component and a fuel cost component based on a 
daily natural gas index, natural gas adders, balancing costs, 
transportation costs, and a risk adder.\317\
---------------------------------------------------------------------------

    \316\ Exelon Comments at 11.
    \317\ Id. at 17-20 (citing Testimony of Leslie O. Dedrickson at 
29-31).
---------------------------------------------------------------------------

    136. Dominion supports a verification process that uses fuel 
estimates based on recent prices, historical prices during similar 
conditions, or a combination of both.\318\ Dominion would support 
allowing market participants to submit cost-based offers within a 
reasonable range of a reference price that would be based on a 
historical fuel price index or an average of ask prices within a given 
fuel market, and that offers which fall in the range of that reference 
price and clear the market should be eligible to set LMP.\319\
---------------------------------------------------------------------------

    \318\ Dominion Comments at 5.
    \319\ Id.
---------------------------------------------------------------------------

    137. The New Jersey and Pennsylvania Commissions and OPSI maintain 
that in order to implement the proposal in PJM, resources should be 
required to have a fuel cost policy approved by the Market Monitoring 
Unit prior to submission of cost-based incremental energy offers above 
$1,000/MWh.\320\ The Pennsylvania Commission states that pre-approved 
resource fuel cost policies in PJM would speed up the verification 
process, foster market stability, and provide certainty to 
resources.\321\ The New Jersey Commission and OPSI assert that resource 
fuel cost policies should be derived from a verifiable, algorithmic, 
and systematic approach consistent with the PJM Market Monitor's fuel 
cost policy guidelines.\322\ The Delaware and Pennsylvania Commissions 
and OPSI argue that PJM should clarify the role of PJM and the PJM 
Market Monitor in the review and approval of fuel cost policies and 
assert that the PJM Market Monitor should have the authority to verify 
offers above $1,000/MWh.\323\
---------------------------------------------------------------------------

    \320\ New Jersey Commission Comments at 12-13; Pennsylvania 
Commission Comments at 9; OPSI Comments at 7-9. This issue was also 
raised in comments in PJM's offer flexibility proposal in Docket No. 
ER16-372-000.
    \321\ Pennsylvania Commission Comments at 9.
    \322\ New Jersey Commission Comments at 13; OPSI Comments at 8 
(citing Monitoring Analytics, Fuel Cost Policy Guidelines: Gas 
Replacement Cost (Sept. 24, 2015), available at http://www.monitoringanalytics.com/reports/Market_Messages/Messages/IMM_Fuel_Cost_Policy_Guidelines_20150924.pdf).
    \323\ Delaware Commission Comments at 12; OPSI Comments at 7-9.
---------------------------------------------------------------------------

    138. SCE argues that each RTO/ISO should utilize its own 
stakeholder processes to develop specific verification rules, which may 
reflect regional factors such as differences in market power mitigation 
processes and region-specific costs such as emissions and greenhouse 
gas costs.\324\
---------------------------------------------------------------------------

    \324\ SCE Comments at 1-2.
---------------------------------------------------------------------------

3. Determination
    139. We adopt the NOPR proposal and clarify that each RTO/ISO or 
Market Monitoring Unit is required to verify that any incremental 
energy offer above $1,000/MWh reasonably reflects the associated 
resource's actual or expected costs prior to using that offer to 
calculate LMPs. We find that this verification requirement is necessary 
for incremental energy offers above $1,000/MWh because market power 
concerns are heightened when a resource's short-run marginal costs 
exceed $1,000/MWh.
    140. Based on the record, it is not practical to require that RTOs/
ISOs or Market Monitoring Units verify a resource's actual costs in all 
circumstances because a resource may not know its actual short-run 
marginal costs at the time it submits an incremental energy offer to 
the RTO/ISO for various reasons, including the timing of natural gas 
procurement. Accordingly, we clarify that an RTO/ISO or a Market 
Monitoring Unit must verify that cost-based incremental energy offers 
above $1,000/MWh reasonably reflect a resource's actual or expected 
costs. Under this requirement, the verification process for cost-based 
incremental offers above $1,000/MWh must ensure that a resource's cost-
based incremental energy offer reasonably reflects that resource's 
actual or expected costs.
    141. The RTO/ISO or Market Monitoring Unit, as prescribed in the 
RTO/ISO tariff and consistent with Order No. 719,\325\ must verify the 
costs within a cost-based incremental energy offer above $1,000/MWh 
before that offer is used to calculate LMP, subject to the condition 
that such offers are capped at $2,000/MWh for purposes of calculating 
LMP.\326\ To create such a verification process, we expect that the 
RTO/ISO would build on its existing mitigation processes for 
calculating or updating cost-based incremental energy offers.\327\ 
However, we appreciate statements from RTOs/ISOs, market monitors, and 
others about potential verification processes for incremental energy 
offers above $1,000/MWh. We recognize that the verification process for 
incremental energy offers may be a fact-specific inquiry, and we have 
previously provided Market Monitoring Units with flexibility to make 
case-specific determinations.\328\ Given the potential complexities 
involved in verifying incremental energy offers as well as the 
Commission's recognition of the need for proper mitigation methods in 
energy markets, we will require that RTOs/ISOs explain in their 
compliance filings what factors will be considered by the RTO/ISO or 
its Market Monitoring Unit in the verification process for cost-based 
incremental energy offers above $1,000/MWh and whether such factors are 
currently considered in existing market power mitigation provisions or 
whether new practices or tariff provisions are necessary given the 
verification requirement adopted in this Final Rule. Therefore, we 
disagree that the verification requirement is needlessly cumbersome 
because RTOs/ISOs may build on existing processes for market power 
mitigation.
---------------------------------------------------------------------------

    \325\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at PP 370-375 
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ] 
31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ] 61,252 
(2009). See also 18 CFR 35.28(g)(3)(iii)(B) (2016).
    \326\ Pursuant to 18 CFR 35.28(g)(3)(iii)(B), either the 
internal or external market monitor can ``provide the inputs 
required to conduct prospective mitigation . . . including, but not 
limited to reference levels, identification of system constraints, 
and cost calculations.'' 18 CFR 35.28(g)(3)(iii)(B) (2016). However, 
prospective mitigation may only be carried out by an internal market 
monitor if the RTO/ISO has a hybrid Market Monitoring Unit 
structure. 18 CFR 35.28(g)(3)(iii)(D) (2016).
    \327\ NOPR, FERC Stats. & Regs. ] 32,714 at P 63.
    \328\ See New England Power Generators Association, Inc. v. ISO 
New England Inc., 144 FERC ] 61,157, at P 62 (2015).
---------------------------------------------------------------------------

    142. Most RTOs/ISOs prohibit incremental energy offers above 
$1,000/MWh, a prohibition that some market

[[Page 87789]]

monitors characterize as a backstop market power mitigation 
measure.\329\ The offer cap adopted in this Final Rule retains the 
backstop function that the current $1,000/MWh offer cap plays in 
existing RTO/ISO market power mitigation because it limits incremental 
energy offers that are not cost-based to $1,000/MWh. Under this Final 
Rule, incremental energy offers below $1,000/MWh will remain subject to 
existing market power mitigation measures. However, this Final Rule 
will require that all incremental energy offers equal to and above 
$1,000/MWh be cost-based, which essentially requires mitigation of all 
incremental energy offers above $1,000/MWh.
---------------------------------------------------------------------------

    \329\ NOPR, FERC Stats. & Regs. ] 32,714 at P 23.
---------------------------------------------------------------------------

    143. In this way, the verification requirement requires RTOs/ISOs 
to make only an incremental change to their existing market power 
mitigation procedures because the market power mitigation provisions 
that apply to incremental energy offers below $1,000/MWh will be 
unchanged. While in this Final Rule we increase the offer cap for cost-
based incremental energy offers, we also subject offers above $1,000/
MWh to additional market power mitigation in the form of the 
verification requirement. The verification requirement is designed to 
ensure that a cost-based incremental energy offer above $1,000/MWh is 
not an attempt by the associated resource to exercise market power. The 
verification requirement is part-and-parcel with the increase of the 
offer cap for cost-based incremental energy offers. We find that it 
would be inappropriate to raise the offer cap without imposing a 
verification requirement. The verification requirement thus serves as 
an additional backstop market power mitigation measure.\330\
---------------------------------------------------------------------------

    \330\ Moreover, existing Commission regulations establish that 
misrepresenting costs when submitting cost-based incremental energy 
offers as part of a supply offer may be in violation of 18 CFR 
35.41(b) (2016) and 18 CFR 1c.2(a)(2) (2016).
---------------------------------------------------------------------------

    144. Contrary to Potomac Economics' assertion that competition is 
not diminished when short-run marginal costs rise above $1,000/MWh, we 
find that market power concerns are heightened during such periods 
because short-run marginal costs in this range may indicate that very 
few resources are available to provide additional supply. Supply may be 
limited during such periods because of fuel supply limitations or the 
physical limitations of resources (e.g., ramping constraints). 
Accordingly, resources with available supply during such periods likely 
face little competition, particularly in real-time, and may therefore 
be able to exercise market power. We find that the verification 
requirement reasonably addresses market power concerns associated with 
incremental energy offers above $1,000/MWh because such offers will be 
required to be cost-based, which should deter attempts by resources to 
exercise market power.
    145. As discussed above, this Final Rule will require RTOs/ISOs to 
limit incremental energy offers to $2,000/MWh when calculating LMPs, 
which may be below the cost-based incremental energy offer of a 
resource. Thus, we revise the verification requirement proposed in the 
NOPR as indicated below and add new language (underlined below) to 
account for any uplift associated with the $2,000/MWh hard cap and 
adopt the following verification requirement:

    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.

    146. We will retain the proposal in the NOPR which ensures that, if 
a resource's incremental energy offer above $1,000/MWh is not verified 
but that resource is nonetheless dispatched, that resource would be 
eligible to receive an uplift payment to recover its verified costs. 
The basis of the uplift payment would be the difference between a given 
resource's energy market revenues and that resource's actual short-run 
marginal costs of the MWs dispatched, as verified after-the-fact by the 
RTO/ISO or Market Monitoring Unit.\331\ We find that such uplift 
payments are necessary given the challenges associated with the 
verification processes, to ensure that resources have an incentive to 
offer into RTO/ISO energy markets, and to ensure that resources are 
compensated for the service they provide.
---------------------------------------------------------------------------

    \331\ The Commission notes that the clarification regarding use 
of a resource's actual or expected short-run marginal costs during 
the verification process that occurs prior to the market clearing 
process is not applicable to such uplift payments. Any such uplift 
payment, which is paid after-the-fact, must be based on a resource's 
actual short-run marginal costs.
---------------------------------------------------------------------------

    147. This Final Rule will permit regional variation in the process 
for treating incremental energy offers above $1,000/MWh that the RTO/
ISO or Market Monitoring Unit cannot verify prior to the start of the 
market clearing process. For example, the RTO/ISO could have procedures 
to change the incremental energy offer to $1,000/MWh or to mitigate 
that offer to a level below $1,000/MWh pursuant to other applicable 
market power mitigation provisions.

C. Resource Neutrality

1. NOPR Proposal
    148. In the NOPR, the Commission proposed the following resource 
neutrality requirement:

    All resources, regardless of type, are eligible to submit cost-
based incremental energy offers in excess of $1,000/MWh.\332\
---------------------------------------------------------------------------

    \332\ NOPR, FERC Stats. & Regs, ] 32,714 at P 69.

    The Commission reasoned that this requirement would ensure that the 
eligibility to submit cost-based incremental energy offers in excess of 
$1,000/MWh would not be applied in an unduly discriminatory or unduly 
preferential manner.\333\ The Commission also stated that the proposed 
resource neutrality requirement is consistent with prior orders related 
to the offer cap in PJM and MISO.\334\
---------------------------------------------------------------------------

    \333\ Id.
    \334\ Id. (citing MISO 2014/15 Offer Cap Order, 150 FERC ] 
61,083 at P 16; PJM 2014/15 Offer Cap Order, 150 FERC ] 61,020 at P 
39).
---------------------------------------------------------------------------

2. Comments
    149. Several commenters support the proposed resource neutrality 
requirement.\335\ For example, MISO supports the resource neutrality 
requirement and notes that the MISO tariff currently allows any 
resource, regardless of type, to establish a cost-based reference 
level.\336\ MISO adds that some resources could be constrained by the 
$1,000/MWh cap because they may be unable to provide evidence of high 
fuel costs.\337\
---------------------------------------------------------------------------

    \335\ EEI Comments at 1, 3; Ohio Commission Comments at 12; MISO 
Comments at 12.
    \336\ MISO Comments at 12 (citing MISO Tariff, Module D, 
64.1.4.a, 64.3.a, and 64.1.4.h).
    \337\ Id.
---------------------------------------------------------------------------

    150. Commenters disagree about whether demand response resources 
should be able to submit incremental energy offers above $1,000/MWh. 
Some commenters argue that demand response resources should be treated 
the same as other physical generation resources that provide 
offers.\338\

[[Page 87790]]

Additionally, MISO questions why a demand response resource should be 
prevented from submitting an offer at the same level (in $/MWh) as 
physical resources.\339\
---------------------------------------------------------------------------

    \338\ API Comments at 12-13; Competitive Suppliers Comments at 
23-24; Exelon Comments at 23 (citing PJM Manual 11 2.3.3); 
Industrial Customers Comments at 28; PJM Market Monitor Comments at 
12-13.
    \339\ MISO Comments at 7.
---------------------------------------------------------------------------

    151. However, other commenters argue that demand response should 
not be able to submit incremental energy offers above $1,000/MWh. PJM/
SPP argue that the proposed offer cap revisions should not apply to 
demand response resources because demand response resource offers are 
intended to capture foregone commercial revenues, not the short-run 
marginal cost of reducing output.\340\ ISO-NE asserts that a demand 
response resource's costs would be based on its marginal opportunity 
cost of foregone consumption, which could routinely exceed $1,000/MWh 
or $2,000/MWh, and that verifying such costs could not be accomplished 
on short notice. ISO-NE surmises that allowing demand resources to 
submit incremental energy offers above $1,000/MWh could create perverse 
incentives and may give physical resources the incentive to move behind 
the meter to exploit asymmetries in the application of the offer cap. 
Accordingly, ISO-NE requests that the Commission carefully consider its 
position on verification of the actual costs of demand response 
resources.\341\
---------------------------------------------------------------------------

    \340\ PJM/SPP Comments at 5.
    \341\ ISO-NE Comments at 7-8.
---------------------------------------------------------------------------

    152. The New Jersey Commission argues that in the absence of a 
comprehensive definition of short-run marginal costs for demand 
response resource offers, demand response resources should not be 
permitted to offer and set the market clearing price above the 
Commission's determined offer cap.\342\ The Pennsylvania Commission 
asserts that demand response resources should not be eligible to set 
LMP and should be treated as price takers, asserting that such 
resources do not generally exhibit competitive behavior in energy 
markets because the energy revenues of such resources are de minimis 
relative to their capacity market revenues.\343\
---------------------------------------------------------------------------

    \342\ New Jersey Commission Comments at 18.
    \343\ Pennsylvania Commission Comments at 14 (citing PJM, Demand 
Response Operations Market's Activity Report: February 2016 (Feb. 
16, 2016), Fig. 23; Monitoring Analytics, LLC, State of the Markets 
Report for PJM, Vol. 1., Fig. 10 (Mar. 10, 2016)).
---------------------------------------------------------------------------

    153. Several commenters express concerns about whether RTOs/ISOs or 
Market Monitoring Units can verify the costs of demand response 
resources. For example, ISO-NE asserts that a demand response 
resource's costs would be based on that resource's marginal opportunity 
cost of foregone consumption and other information that is difficult to 
validate, particularly if the demand response resource's costs increase 
significantly from the prior day.\344\ PJM/SPP state that it is not 
clear what demand response resource costs could be validated to justify 
an offer above the $1,000/MWh offer cap.\345\ The Pennsylvania 
Commission states that with the limited exception of on-site backup 
generation costs, the incremental energy costs of demand response 
capacity resources are largely unknown.\346\ ISO-NE urges the 
Commission to carefully consider whether the verification of actual 
costs should be imposed on a resource-neutral basis, and explains its 
concerns regarding its ability to timely verify the offers of demand 
response resources.\347\ AEMA argues that it is impractical, if not 
impossible, to verify the costs of a demand response resource in the 
same manner as a physical generation resource, particularly before-the-
fact.\348\ AEMA also cites a prior Commission order on ISO-NE's Order 
No. 745 compliance where the Commission found that ``unlike with supply 
resources, it would be very difficult to develop a competitive offer or 
reference price to which to mitigate each demand response resource.'' 
\349\ AEMA asserts that there is no need to create an additional 
verification requirement for demand response resources, because the 
Commission has recognized that comparability does not require identical 
treatment.\350\
---------------------------------------------------------------------------

    \344\ ISO-NE Comments at 7-8.
    \345\ PJM/SPP Comments at 5.
    \346\ Pennsylvania Commission Comments at 14.
    \347\ ISO-NE Comments at 7-8.
    \348\ AEMA Comments at 7-8.
    \349\ Id. at 8 (citing ISO New England Inc., 138 FERC ] 61,042, 
at P 138 (2012)).
    \350\ Id. at 8-9 (citing Preventing Undue Discrimination and 
Preference in Transmission Service, Order No. 890, FERC Stats. & 
Regs. ] 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs. 
] 31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299, 
at P 216 (2008), order on reh'g, Order No. 890-C, 126 FERC ] 61,228, 
order on clarification, Order No. 890-D, 129 FERC ] 61,126 (2009); 
Indep. Market Monitor for PJM v. PJM Interconnection, L.L.C., 155 
FERC ] 61,059, at P 31 (2016) (``comparability does not require 
identical application to demand response resources and generation 
resources of PJM's offer cap and the must-offer requirement'')).
---------------------------------------------------------------------------

    154. AEMA requests that the Commission clarify that the offer cap 
proposed in the NOPR only impacts demand response resources that 
participate in energy markets and would not apply to demand resources 
that exclusively participate in capacity markets.\351\ AEMA explains 
that demand response resources that participate exclusively in capacity 
markets do not make incremental energy offers. AEMA explains that 
capacity-only demand response resources are only dispatched on a 
reliability-based trigger that determines the price the demand resource 
is paid as opposed to an offer price-based trigger that does not 
represent the LMP at which the customer wishes to be dispatched, or the 
costs of the customer to curtail its load. AEMA asserts that forcing 
these resources to make ``incremental energy offers'' in the energy 
market would drive them away from participation.\352\
---------------------------------------------------------------------------

    \351\ Id. at 3.
    \352\ Id. at 3-5.
---------------------------------------------------------------------------

    155. AEMA requests that the Commission continue to allow demand 
response resources to submit offers up to the offer cap in energy 
markets and not impose additional verification requirements on demand 
response resource energy market offers beyond what has already been 
accepted.\353\ AEMA asserts that the Final Rule should not impact 
existing or proposed methods for monitoring and evaluating demand 
resource offers in energy markets or create additional verification 
hurdles for demand resource offers beyond those that currently 
exist.\354\
---------------------------------------------------------------------------

    \353\ Id. at 5-6.
    \354\ Id. at 2-3, 7-9.
---------------------------------------------------------------------------

3. Determination
    156. We adopt the NOPR proposal and find that resources with costs 
above $1,000/MWh should be able to submit cost-based incremental energy 
offers to recover their costs, regardless of the type of resource. 
Prohibiting a particular set of resources from submitting cost-based 
incremental energy offers above $1,000/MWh could preclude them from 
recovering their costs.
    157. In the NOPR the term ``resource'' referred to all supply 
resources, including demand response resources, that offer incremental 
energy to RTO/ISO energy markets.\355\ As such, a demand response 
resource that submits incremental energy offers to the energy market 
based on short-run marginal cost would be subject to the verification 
requirement if that incremental energy offer exceeds $1,000/MWh. For 
such a resource, the short-run marginal cost may equal its opportunity 
costs.
---------------------------------------------------------------------------

    \355\ This is consistent with prior uses of the term. See, e.g., 
Settlement Intervals and Shortage Pricing in Markets Operated by 
Regional Transmission Organizations and Independent System 
Operators, Order No. 825, 81 FR 42,882 (June 30, 2015), FERC Stats. 
& Regs. ] 31,384, at P 98 (2016).
---------------------------------------------------------------------------

    158. We recognize that the verification process for demand response 
resources will necessarily differ from the verification process for 
generation resources, as noted by ISO-NE and AEMA. The Commission has

[[Page 87791]]

recognized that demand response resources should receive comparable, 
but not necessarily identical treatment to generation resources.\356\ 
However, we decline AEMA's request to exempt demand response resources 
that submit incremental energy offers in RTO/ISO energy markets from 
any additional verification requirements associated with this Final 
Rule, because such an exemption does not constitute comparable 
treatment. However, as noted above,\357\ this Final Rule does not 
prescribe how RTOs/ISOs should verify cost-based incremental energy 
offers above $1,000/MWh, including offers from demand response 
resources.
---------------------------------------------------------------------------

    \356\ Demand Response Compensation in Organized Wholesale Energy 
Markets, Order No. 745, FERC Stats. & Regs. ] 31,322, at P 66, order 
on reh'g and clarification, Order No. 745-A, 137 FERC ] 61,215 
(2011) (``as a general matter demand response providers and 
generators should be subject to comparable rules that reflect the 
characteristics of the resource.'').
    \357\ See supra P 141.
---------------------------------------------------------------------------

    159. Finally, we find that the New Jersey and Pennsylvania 
Commissions' comments that demand response resources should not be able 
to set LMP are beyond the scope of this Final Rule, which only applies 
to incremental energy offers above $1,000/MWh, and not the general 
eligibility of demand response resources to set LMPs in RTO/ISO energy 
markets. We clarify, however, that reforms adopted in this Final Rule, 
which provide that resources are eligible to submit cost-based 
incremental energy offers in excess of $1,000/MWh and require that 
those offers be verified, do not apply to capacity-only demand response 
resources that do not submit incremental energy offers in energy 
markets.

V. Other Issues

A. Virtual Transactions

    160. Although the Commission preliminarily found in the NOPR that 
virtual supply offers and virtual demand bids (virtual transactions) 
could not provide a cost basis for offers above $1,000/MWh, it sought 
comment about whether prohibiting virtual transactions above $1,000/MWh 
could limit hedging opportunities, present opportunities for 
manipulation or gaming, create market inefficiencies, or have other 
undesirable consequences.\358\
---------------------------------------------------------------------------

    \358\ NOPR, FERC Stats. & Regs ] 32,714 at PP 64, 73.
---------------------------------------------------------------------------

1. Comments
    161. CAISO states that virtual transactions do not face short-run 
marginal production costs and would thus be unable to justify costs 
above $1,000/MWh.\359\ However, CAISO notes that if physical resources 
can submit incremental energy offers above $1,000/MWh, then virtual 
participants should also be able to bid above $1,000/MWh to arbitrage 
those physical offers.\360\
---------------------------------------------------------------------------

    \359\ CAISO Comments at 13.
    \360\ Id.
---------------------------------------------------------------------------

    162. ISO-NE states that market participants should be able to 
submit virtual supply offers at levels as high as offers from physical 
resources to ensure that there is a liquid supply of offers that can 
compete with physical resources in the day-ahead market under all 
market conditions, which can reduce the potential exercise of market 
power during tight day-ahead conditions.\361\ ISO-NE asserts that if 
the Commission adopts a new hard cap, there is no cost-basis or market 
power rationale to limit virtual supply offers below the level of any 
hard cap.\362\
---------------------------------------------------------------------------

    \361\ ISO-NE Comments at 8.
    \362\ Id. at 8-9.
---------------------------------------------------------------------------

    163. PJM argues that virtual transactions should be permitted to 
exceed $1,000/MWh or be subject to a reasonableness screen because 
virtual transactions increase competition in the day-ahead markets and 
reduce market share, and thus reduce market power.\363\ MISO states 
that prohibiting virtual transactions above $1,000/MWh could limit 
hedging opportunities which could increase the price differentials 
between the day-ahead and real-time energy markets.\364\ MISO adds that 
revising the offer cap for virtual transactions could conceivably 
expose other market participants to high prices but notes that MISO 
already has mitigation measures in place for virtual transactions and 
that years of market experience have shown that such manipulation 
concerns are improbable.\365\
---------------------------------------------------------------------------

    \363\ PJM/SPP Comments at 27.
    \364\ MISO Comments at 18; see also PJM/SPP Comments at 27-28.
    \365\ MISO Comments at 18.
---------------------------------------------------------------------------

    164. NYISO states that cost-based incremental energy offers, 
interchange transactions (e.g., imports and exports), and virtual 
transactions should be capped at the level of the hard cap, which will 
allow market participants to continue to compete to the maximum extent 
practicable.\366\ NYISO also argues that a hard cap is appropriate for 
virtual transactions because such transactions are based on price 
expectations as opposed to verifiable costs.\367\ SPP states that it 
takes no position on the application of the proposed reforms to virtual 
transactions.\368\
---------------------------------------------------------------------------

    \366\ NYISO Comments at 7-8.
    \367\ Id. at 7.
    \368\ PJM/SPP Comments at 28.
---------------------------------------------------------------------------

    165. Potomac Economics states that competitive virtual transactions 
should be permitted to exceed $1,000/MWh when real-time prices are 
expected to exceed $1,000/MWh.\369\ Potomac Economics states that 
although virtual transactions do not have production costs, they do 
have marginal costs, and notes that the marginal cost of selling 
virtual energy in the day-ahead market is the expected cost of buying 
the energy in the real-time market.\370\ Potomac Economics states that 
virtual transactions support the competitive performance of day-ahead 
markets and thus argues that it is important to structure the rules for 
virtual transactions in a manner that does not impede their 
participation in the market.\371\
---------------------------------------------------------------------------

    \369\ Potomac Economics Comments at 10.
    \370\ Id.
    \371\ Id.
---------------------------------------------------------------------------

    166. Potomac Economics proposes that virtual transactions be 
permitted to exceed $1,000/MWh when real-time LMPs are expected to 
exceed $1,000/MWh for more than a specified period (e.g., 30 
minutes).\372\ The PJM Market Monitor argues that market participants 
should not be permitted to submit virtual transactions above $1,000/MWh 
because increasing the offer cap on virtual transactions would create 
opportunities for the exercise of market power and manipulation of 
markets and permit resource owners to avoid the requirement that 
incremental energy offers above $1,000/MWh be cost-based.\373\ The PJM 
Market Monitor states there is no evidence that virtual supply offers 
have increased competition or would increase competition in extreme 
circumstances.\374\ The PJM Market Monitor recommends that if the 
Commission wishes to permit some virtual transactions to exceed $1,000/
MWh, the Commission should: (1) Limit virtual transactions above 
$1,000/MWh to liquid trading hubs; (2) require market participants to 
explain why virtual offers or bids above $1,000/MWh are appropriate; 
and (3) subject such virtual transactions to a ``reasonableness 
screen'' and an after-the-fact review for whether they resulted in 
manipulation or market power.\375\ The PJM Market Monitor states that 
the asserted benefits of virtuals with respect to hedging, competition, 
and price convergence have not been empirically established, and, thus, 
it is unnecessary to create

[[Page 87792]]

market power risks when revising the offer cap.\376\
---------------------------------------------------------------------------

    \372\ Id. at 9-10.
    \373\ PJM Market Monitor Comments at 11; PJM Market Monitor 
Answer at 6.
    \374\ PJM Market Monitor Answer at 5.
    \375\ PJM Market Monitor Comments at 11-12.
    \376\ PJM Market Monitor Answer at 5.
---------------------------------------------------------------------------

    167. Separately, the PJM Market Monitor recommends that up-to-
congestion transactions in PJM be excluded from any offer cap reforms 
stating that because up-to-congestion transactions are spread bids 
between nodes there is no reason to relax the current rules that govern 
such transactions.\377\
---------------------------------------------------------------------------

    \377\ PJM Market Monitor Comments at 11; PJM Market Monitor 
Answer at 6.
---------------------------------------------------------------------------

    168. Several commenters argue that the Commission should allow 
virtual transactions to exceed $1,000/MWh.\378\ Some commenters focus 
on the use of virtual transactions to hedge physical transactions and 
argue that virtual transactions should thus be subject to the same 
offer caps as physical resources.\379\ Dominion states that in extreme 
winter conditions, a physical resource that faces a start-up risk and 
is likely to receive a day-ahead award may submit a virtual demand bid 
to hedge against the potential outage in real-time.\380\ Exelon also 
argues that hedging the risk of physical transactions through virtual 
transactions is especially important when the system is stressed, and 
that doing so may improve market performance by converging day-ahead 
and real-time prices.\381\ Competitive Suppliers assert that the same 
argument articulated in the NOPR for having a uniform offer cap across 
regions demands similar treatment of virtual transactions, imports, and 
emergency demand response across regions.\382\
---------------------------------------------------------------------------

    \378\ Competitive Suppliers Comments at 23-24; Dominion Comments 
at 7; Exelon Comments at 23-24; ISO-NE Comments at 8; PJM/SPP 
Comments at 27; SPP Market Monitor Comments at 12; NY Department of 
State Comments at 6.
    \379\ SPP Market Monitor Comments at 12; Competitive Suppliers 
Comments at 23-24; NY Department of State Comments at 6; Dominion 
Comments at 7.
    \380\ Dominion Comments at 7.
    \381\ Exelon Comments at 23-24.
    \382\ Competitive Suppliers Comments at 23.
---------------------------------------------------------------------------

    169. Dominion states that limiting the ability to submit virtual 
transactions above $1,000/MWh to physical resources with verified cost-
based incremental energy offers above $1,000/MWh in order to allow such 
resources to hedge would minimize concerns about market 
manipulation.\383\ The PJM Market Monitor responds that Dominion's 
proposal creates a significant risk of manipulation because Dominion 
does not propose to limit the virtual bids to the cost-based offer of 
the generator.\384\
---------------------------------------------------------------------------

    \383\ Dominion Comments at 7.
    \384\ PJM Market Monitor Answer at 6.
---------------------------------------------------------------------------

    170. Several other commenters argue that virtual transactions 
should be prohibited from submitting transactions above $1,000/
MWh.\385\ For example, several commenters argue that virtual 
transactions should not be permitted to exceed $1,000/MWh because 
allowing transactions in this range could raise clearing prices without 
a commensurate increase in short-run marginal production costs.\386\ 
Six Cities argues that permitting virtual transactions to submit offers 
above the $1,000/MWh cap would be inconsistent with the Commission's 
goals of allowing recovery of actual production costs in excess of the 
cap and establishing LMPs consistent with actual production costs under 
extreme market conditions.\387\ TAPS argues that the Commission does 
not need to allow virtual transactions to exceed $1,000/MWh to 
encourage price convergence between the day-ahead and real-time 
markets.\388\
---------------------------------------------------------------------------

    \385\ APPA, NRECA, and AMP Comments at 19; Industrial Customers 
Comments at 28-29; Ohio Commission Comments at 14; New Jersey 
Commission Comments at 17-18; Six Cities Comments at 3.
    \386\ Industrial Customers Comments at 28-29; New Jersey 
Commission Comments at 17-18; Six Cities Comments at 3; Ohio 
Commission Comments at 14; TAPS Comments at 20-21.
    \387\ Six Cities Comments at 4.
    \388\ TAPS Comments at 21.
---------------------------------------------------------------------------

    171. Some commenters argue, as the PJM Market Monitor does, that 
allowing virtual transactions above the $1,000/MWh cap could lead to 
undesirable consequences, such as creating the opportunity for market 
manipulation and the exercise of market power.\389\ For example, SCE 
cautions that allowing virtuals above $1,000/MWh would undermine the 
purpose of having a backstop for existing market power mitigation 
rules.\390\ APPA, NRECA, and AMP state that although they oppose the 
idea, any proposal to allow virtual transactions above $1,000/MWh must 
be accompanied by an assurance that the RTO/ISO and/or Market 
Monitoring Unit will be able to address any gaming or anti-competitive 
conduct.\391\ PG&E asks that the Commission direct market monitors to 
study the potential impacts and gaming opportunities associated with 
permitting virtual transactions above $1,000/MWh before revising any 
caps on virtual transactions.\392\ Midcontinent Joint Consumer 
Advocates state that while it generally supports applying the same 
offer cap to physical and virtual transactions, the issue should be 
monitored to ensure that inappropriate virtual transactions do not 
affect real-time energy prices.\393\ The Delaware Commission recommends 
that virtual transactions in PJM be limited to $400/MWh.\394\
---------------------------------------------------------------------------

    \389\ APPA, NRECA, and AMP Comments at 19; ODEC Comments at 1; 
KEPCo/NCEMC Comments at 5; New Jersey Commission Comments at 18; PJM 
Market Monitor Comments at 11-12; TAPS Comments at 21.
    \390\ SCE Comments at 2.
    \391\ APPA, NRECA, and AMP Comments at 19.
    \392\ PG&E Comments at 3-4.
    \393\ Midcontinent Joint Consumer Advocates Comments at 9.
    \394\ Delaware Commission Comments at 14. The Delaware 
Commission recommends that in PJM, virtual transactions and 
incremental energy offers that are not cost-based be limited to 
$400/MWh.
---------------------------------------------------------------------------

2. Determination
    172. In light of the comments received and our adoption of a 
$2,000/MWh hard cap, we find that it is just and reasonable to permit 
market participants to submit virtual transactions up to $2,000/MWh. We 
do not require that virtual transactions be subject to the cost 
verification described above. Allowing virtual transactions above 
$1,000/MWh could improve price convergence between day-ahead and real-
time markets.\395\ An offer cap that is lower for virtual transactions 
than for physical resources could increase divergence between day-ahead 
and real-time LMPs. This finding is consistent with prior Commission 
precedent, which finds it is reasonable to permit market participants 
to submit virtual transactions at levels commensurate with the levels 
that real-time LMPs can reach.\396\
---------------------------------------------------------------------------

    \395\ PJM Interconnection, L.L.C., 139 FERC ] 61,057 (2012).
    \396\ Id. PP 123-126. In that order, the Commission found that 
``if virtual traders and demand cannot submit higher bids in the 
day-ahead market [commensurate with the $/MWh value that real-time 
LMPs can reach if shortage pricing is in effect], that market may 
not converge with prices in the real-time market during times when 
PJM experiences shortage conditions in the real-time market.'' Id. P 
124.
---------------------------------------------------------------------------

    173. We find that market participants should be allowed to submit 
virtual transactions up to the hard cap, as they can today. As such, 
this Final Rule is therefore less likely to result in unintended 
consequences associated with capping virtual transactions at a level 
below the hard cap. For example, capping virtual transactions at 
$1,000/MWh when the incremental energy offers used to calculate LMPs 
are capped at $2,000/MWh could encourage some market participants to 
place virtual demand bids at $1,000/MWh, a transaction that may be 
profitable if real-time prices exceed $1,000/MWh but would not 
contribute to day-ahead and real-time price convergence.
    174. Under this Final Rule, LMPs may rise above $1,000/MWh. By 
permitting virtual transactions to exceed $1,000/MWh, we preserve a 
market participant's ability to use virtual

[[Page 87793]]

transactions to hedge its exposure to real-time LMPs above $1,000/MWh. 
Otherwise, if virtual transactions are limited to $1,000/MWh, as 
proposed in the NOPR, a market participant would be barred from placing 
virtual transactions commensurate with its market risks.
    175. We also find that allowing virtual transactions above $1,000/
MWh may add liquidity to day-ahead markets. Permitting virtual 
transactions in the $1,000/MWh--$2,000/MWh range could result in 
additional demand bids and supply offers (i.e., virtual demand bids and 
virtual supply offers) and will thus allow virtual transactions to 
continue to perform the functions that they do today by adding 
liquidity to the day-ahead market.
    176. We recognize that virtual transactions, by their nature, 
cannot be subjected to the type of cost-verification discussed above. 
However, in response to comments arguing that virtual transactions 
above $1,000/MWh will raise LMPs above verifiable costs and/or result 
in market power abuse, we note that Market Monitoring Units currently 
monitor for anti-competitive behavior by market participants. While 
they are not required to do so, if RTOs/ISOs determine that additional 
measures are necessary to address any concerns that arise from 
permitting virtual transactions up to $2,000/MWh, RTOs/ISOs may propose 
such additional measures in a separate filing under section 205 of the 
Federal Power Act.
    177. Dominion proposes to limit the ability to submit virtual 
transactions above $1,000/MWh to physical resources that have cost-
based offers above $1,000/MWh. We find that Dominion's proposal to 
limit virtual transactions to certain market participants would be 
unduly discriminatory. Such a limitation would treat market 
participants differently depending on whether they owned physical 
generation assets, and would be unduly discriminatory because it would 
limit the benefits of virtual transactions above $1,000/MWh to those 
participants with physical assets. Further, such a limitation could 
limit the other potential benefits of virtual transactions above 
$1,000/MWh, such as increased liquidity and increased convergence 
between day-ahead and real-time LMPs. Additionally, we find that the 
PJM Market Monitor's and Potomac Economics' proposals to limit virtual 
transactions above $1,000/MWh to certain time periods or certain 
locations lack sufficient detail and record evidence to make a finding 
that either proposal is just and reasonable. Finally, we clarify that 
this Final Rule does not apply to up-to-congestion transactions in PJM, 
because such transactions are spread bids and not virtual supply offers 
or virtual demand bids.

B. External Transactions

    178. In the NOPR, the Commission stated that external RTO/ISO 
resources (i.e., imports) would not be eligible to submit cost-based 
incremental energy offers above $1,000/MWh because RTO/ISO processes to 
develop cost-based incremental energy offers for mitigation purposes 
typically only apply to internal RTO/ISO resources.\397\ The Commission 
added, however, that it would consider RTO/ISO proposals to verify 
cost-based incremental energy offers from external transactions in 
their respective compliance filings.\398\ The Commission also sought 
comment on whether the offer cap proposal should apply to imports and 
whether a cost verification process for import transactions is 
feasible.\399\
---------------------------------------------------------------------------

    \397\ NOPR, FERC Stats. & Regs ] 32,714 at P 63.
    \398\ Id.
    \399\ Id. PP 63, 73.
---------------------------------------------------------------------------

1. Comments
    179. CAISO maintains that the consistent treatment of internal 
resources and external resources (e.g., imports) is key to an efficient 
market and to avoid unintended consequences.\400\ CAISO surmises that 
capping import offers to a level below the cap that internal resource 
incremental energy offers are subject to could reduce supply offers 
from imports during periods when natural gas prices in the West rise to 
a level that would justify LMPs above $1,000/MWh.\401\
---------------------------------------------------------------------------

    \400\ CAISO Comments at 13.
    \401\ Id.
---------------------------------------------------------------------------

    180. ISO-NE states that it cannot verify the costs associated with 
energy import transactions in real-time.\402\ ISO-NE explains that an 
importer's actual cost to import power into ISO-NE from an adjacent 
market is the adjacent market's real-time LMP, which is determined at 
the same time as ISO-NE's LMP. ISO-NE adds that, given the lack of 
organized markets in some control areas adjacent to ISO-NE., it is 
unclear how actual costs would be verified for import transactions from 
those areas. Accordingly, ISO-NE requests additional guidance from the 
Commission about the application of the proposed rule to imports and 
exports.\403\
---------------------------------------------------------------------------

    \402\ ISO-NE Comments at 9.
    \403\ Id.
---------------------------------------------------------------------------

    181. PJM asserts that non-emergency imports should be allowed to 
submit offers above $1,000/MWh to ensure that economic import 
transactions occur even when PJM LMPs exceed $1,000/MWh because such 
purchases and sales will benefit the market and provide electric 
supplies by allowing the lowest cost energy to serve customers.\404\ 
PJM adds that imports may also defer operational emergency procedures 
in extreme situations.\405\
---------------------------------------------------------------------------

    \404\ PJM/SPP Comments at 25.
    \405\ Id.
---------------------------------------------------------------------------

    182. PJM explains that under PJM's current rules, economic 
transactions are capped at the maximum energy price (absent congestion 
and losses) of $2,700/MWh while emergency import transactions are not. 
PJM states that the value of lost load may exceed this level and states 
that PJM is thus willing to pay more than $2,700/MWh to procure 
emergency energy to prevent load shedding.\406\ PJM notes that the 
verification of import's cost would have to follow a different process 
than internal resources because the resource behind the import is 
frequently unknown.\407\
---------------------------------------------------------------------------

    \406\ Id. at 26 (citing PJM, Intra-PJM Tariffs, OATT, Tariff 
Operating Agreement, Attachment K-Appendix, section 3.2.3.A).
    \407\ Id.
---------------------------------------------------------------------------

    183. SPP states that verifying the costs of imports could be 
problematic because it is difficult to obtain cost information from 
resources outside of SPP.\408\ SPP asks the Commission to allow 
regional flexibility for this issue, noting that it would investigate 
the issue further in response to any Final Rule issued in this 
proceeding.\409\
---------------------------------------------------------------------------

    \408\ Id. at 27.
    \409\ Id.
---------------------------------------------------------------------------

    184. According to the PJM Market Monitor, 99.99 percent of PJM 
imports are price takers but imports that are not price takers should 
continue to be limited to $1,000/MWh offers.\410\ Potomac Economics 
contends that external transactions should be eligible to submit offers 
above $1,000/MWh when prices in the real-time market exceed $1,000/MWh 
for more than a specified period of time (e.g., 30 minutes). Potomac 
Economics also asserts that Coordinated Transaction Schedules should be 
exempt from the proposed reforms because they reflect a forecast of the 
price spread between RTO/ISO markets and thus would not set the LMP in 
either market.\411\
---------------------------------------------------------------------------

    \410\ PJM Market Monitor Comments at 10.
    \411\ Potomac Economics Comments at 9-10.
---------------------------------------------------------------------------

    185. The SPP Market Monitor states that the proposed offer cap 
requirements should apply to imports because imports have the same 
potential impact on LMPs as internal resources. However, the SPP Market 
Monitor acknowledges that it is more challenging to verify the offers 
of

[[Page 87794]]

imports as compared to offers from internal SPP resources because the 
SPP market monitor may have limited access to the cost data of external 
resources.\412\
---------------------------------------------------------------------------

    \412\ SPP Market Monitor Comments at 11.
---------------------------------------------------------------------------

    186. Several commenters assert that imports should be able to offer 
above $1,000/MWh provided the costs in their offers are verified 
beforehand,\413\ and some commenters say it is possible to develop a 
workable solution for such verification.\414\ For example, the New 
Jersey Commission argues that imports that clear the PJM capacity 
auctions, which are pseudo-tied, will have short-run marginal 
production costs that are available for the market monitor to review, 
and should thus be permitted to offer into the PJM energy market above 
$1,000/MWh when their costs exceed $1,000/MWh.\415\ Midcontinent Joint 
Consumer Advocates explain that offers from imports are provided in the 
day-ahead market and then only scheduled in real-time, and imports 
cannot set real-time LMPs in MISO.\416\ However, Midcontinent Joint 
Consumer Advocates state that if imports are the source of higher 
prices in MISO markets, then it would be important to verify the costs 
of imports and in such cases, Midcontinent Joint Consumer Advocates 
would support verification for imports so that all suppliers are 
treated equally.\417\ The Delaware Commission supports the NOPR 
proposal to require verification of exchange transactions provided the 
process in an exporting region is not less objective or rigorous than 
the process in the importing region.\418\
---------------------------------------------------------------------------

    \413\ Delaware Commission Comments at 13; Midcontinent Joint 
Consumer Advocates Comments at 8; Ohio Commission Comments at 13; 
Six Cities Comments at 3.
    \414\ Midcontinent Joint Consumer Advocates Comments at 8; Six 
Cities Comments at 3; CEA Comments at 7-8.
    \415\ New Jersey Commission Comments at 18.
    \416\ Midcontinent Joint Consumer Advocates Comments at 8.
    \417\ Id.
    \418\ Delaware Commission Comments at 13.
---------------------------------------------------------------------------

    187. Powerex asks the Commission to consider adopting a 
verification process for external resources that is distinct from the 
process used for internal resources because the two resource types 
differ.\419\ Powerex states that verifying external resource costs is 
challenging in WECC because large hydroelectric storage facilities in 
the Pacific Northwest do not have easily calculable and verifiable 
short-run marginal costs, and because CAISO does not require that 
import offers be associated with a specific resource.\420\ As an 
alternative, Powerex suggests that the Commission could direct the 
RTOs/ISOs to implement an offer cap tied to prevailing market prices, 
such as capping offers from external resources at the higher of $1,000/
MWh or 120 percent of the highest market price index report in the 
region for the previous seven days.\421\ TAPS and APPA, NRECA, and AMP 
assert that the Commission should give individual RTOs/ISOs the 
discretion to determine whether to allow imports to submit cost-based 
incremental energy offers over $1,000/MWh.\422\
---------------------------------------------------------------------------

    \419\ Powerex Comments at 7-8.
    \420\ Id. at 8-9.
    \421\ Id. at 9.
    \422\ TAPS Comments at 19-20; APPA, NRECA, and AMP Comments at 
18-19.
---------------------------------------------------------------------------

    188. Several commenters argue that limiting external resources to 
$1,000/MWh offers may dissuade them from offering electricity to the 
RTO/ISO in periods when it is most needed.\423\ For example, CEA states 
that in light of the Commission's price formation proceeding, there is 
no compelling reason to adopt an asymmetrical offer cap for internal 
resources and imports and questions the wisdom of excluding external 
transactions when price signals indicate scarcity and extreme 
conditions.\424\ Powerex states that the Western Interconnection has a 
robust market for energy and ancillary services outside of CAISO and 
that non-CAISO resources may make the economically rational choice to 
sell power to a non-CAISO customer if CAISO has a lower offer cap 
compared to the non-CAISO WECC bilateral market.\425\
---------------------------------------------------------------------------

    \423\ NY Transmission Owners Comments at 5-6; CEA Comments at 7-
8; NY Department of State Comments at 5; Powerex Comments at 7-8.
    \424\ CEA Comments at 7-8.
    \425\ Powerex Comments at 7-8.
---------------------------------------------------------------------------

    189. NYISO and Competitive Power Providers state that all market 
transactions, including imports and virtual transactions, should be 
capped at the level of the hard cap, which will allow for a greater 
degree of competition.\426\
---------------------------------------------------------------------------

    \426\ Competitive Suppliers Comments at 23-24; NYISO Comments at 
7.
---------------------------------------------------------------------------

    190. Some commenters discussed emergency imports. For example, PJM 
Power Providers agrees with PJM that the Commission should not apply 
the proposed offer requirements to emergency imports because an offer 
cap on emergency energy or emergency load reductions would limit PJM's 
ability to procure sufficient resources and could threaten 
reliability.\427\
---------------------------------------------------------------------------

    \427\ PJM Power Providers Answer at 6-7.
---------------------------------------------------------------------------

    191. However, the PJM Market Monitor argues that emergency imports 
above $1,000/MWh should be subject to cost verification before they are 
eligible to set LMP in PJM and asserts that such imports currently have 
an unmitigated opportunity to exercise market power in PJM 
markets.\428\ The PJM Market Monitor states that the rules of 
competitive markets should apply, even during emergency 
conditions.\429\ The PJM Market Monitor adds that verifying the costs 
of emergency imports is feasible because they occur infrequently.\430\ 
PJM Market Monitor asserts that PJM/SPP offer no rationale for 
exempting emergency imports from the proposed offer cap requirements, 
which the PJM Market Monitor states are most critical during emergency 
situations.\431\
---------------------------------------------------------------------------

    \428\ PJM Market Monitor Comments at 11; PJM Market Monitor 
Answer at 2-3.
    \429\ PJM Market Monitor Answer at 2.
    \430\ PJM Market Monitor Comments at 11; PJM Market Monitor 
Answer at 3.
    \431\ PJM Market Monitor Answer at 3.
---------------------------------------------------------------------------

2. Determination
    192. We find that it is just and reasonable to permit economic 
exchange transactions (i.e., imports and exports) to offer up to the 
level of the $2,000/MWh hard cap. We do not require that import or 
export transactions above $1,000/MWh be subject to the verification 
requirement prior to the market clearing process.
    193. While in the NOPR the Commission proposed to make imports 
ineligible to offer above $1,000/MWh, i.e., to prohibit imports from 
making such offers, we now are persuaded that such a prohibition could 
discourage imports at times when they are most needed. Imports benefit 
the market because they offer additional supply and increase 
competition. A prohibition on imports above $1,000/MWh would discourage 
external resources with short-run marginal costs above $1,000/MWh from 
supplying energy to the RTO/ISO market, even though the market is 
willing to purchase that supply, and such a prohibition would thus put 
upward pressure on energy prices. We applied this rationale above in 
adopting the offer structure requirement and find that it applies 
equally to imports. Additionally, similar to the rationale outlined 
above for virtual transactions, allowing imports to offer up to $2,000/
MWh without cost verification is generally consistent with the current 
market structures in RTOs/ISOs, which typically allow imports to offer 
up to the same offer cap that internal RTO/ISO resources are subject 
to. A similar logic applies to export transactions.
    194. Further, prohibiting imports from offering above $1,000/MWh 
could result in uneconomic flows between RTOs/ISOs. For example, if the 
LMP in one

[[Page 87795]]

RTO/ISO is $1,500/MWh and an external resource would like to offer an 
import at a price of $1,400/MWh, a prohibition on import offers above 
$1,000/MWh would restrict that transaction and result in inefficient 
flows across RTO/ISO boundaries.
    195. Additionally, we will not require import offers above $1,000/
MWh be cost-verified and find that imports are not similarly situated 
to internal generation resources. Unlike incremental energy offers from 
internal resources, import offers are often not resource-specific and, 
thus, it is difficult--some commenters say impossible--to ascertain the 
underlying costs of most import offers. This approach is consistent 
with current market power mitigation measures in RTOs/ISOs that apply 
to internal resources but do not typically apply to imports.
    196. Additionally, RTO/ISO market participants can import energy 
from adjacent markets and sell that energy in the RTO/ISO energy 
market. Therefore, it is difficult for external resources in an 
adjacent market to withhold because internal RTO/ISO resources can 
import energy from that adjacent market. Additionally, provided the 
adjacent market is competitive, which is expected if the adjacent 
market is an RTO/ISO with market power mitigation, it would be 
difficult for an external resource to exercise market power in the 
importing RTO/ISO.
    197. Though it is not required, the Commission would consider 
proposals by RTOs/ISOs to verify or otherwise review the costs of 
imports or exports and/or develop additional mitigation provisions for 
import and export transactions above $1,000/MWh. Such proposals should 
be submitted in a separate filing under section 205 of the Federal 
Power Act.
    198. We clarify that this Final Rule will not apply to Coordinated 
Transactions Schedules, which are spread bids as opposed to energy 
offers. Additionally, the Final Rule will not apply to emergency 
purchases, which would go beyond the scope of this Final Rule because 
such transactions are administratively priced rather than based on 
short-run marginal cost.

VI. Other Comments

    199. The Commission also sought comment on various aspects of the 
verification process and the types of costs that should be considered 
in the verification. Specifically, the Commission sought comment on (1) 
whether the Market Monitoring Unit or RTOs/ISOs may need additional 
information to ensure that all short-run marginal cost components that 
are difficult to quantify, such as certain opportunity costs, are 
accurately reflected in a resource's cost-based incremental energy 
offer, and (2) to the extent that RTOs/ISOs currently include an adder 
above cost in cost-based incremental energy offers, whether such an 
adder is appropriate for incremental energy offers above $1,000/
MWh.\432\ Commenters also discussed the impact that the proposed offer 
cap reforms could have on other market constructs, such as shortage 
pricing.
---------------------------------------------------------------------------

    \432\ NOPR, FERC Stats. & Regs. ] 32,714 at P 73.
---------------------------------------------------------------------------

A. Verification Requirement Details

1. Comments
    200. Commenters express differing views on whether opportunity 
costs are legitimate costs, and if so, whether it is appropriate to 
include them within cost-based incremental energy offers. The PJM 
Market Monitor states that it currently calculates opportunity costs at 
the request of PJM members and does not need additional information 
about the details of opportunity costs.\433\ The SPP Market Monitor 
explains that SPP currently allows an opportunity cost adder above 
mitigated offers, which would still be appropriate to include if costs 
exceed $1,000/MWh.\434\
---------------------------------------------------------------------------

    \433\ PJM Market Monitor Comments at 8.
    \434\ SPP Market Monitor Comments at 10. The SPP Market Monitor 
notes that resources can use forecasted LMPs and production costs to 
estimate price-cost margins for each hour of the day to determine 
the opportunity cost component of the mitigated offer.
---------------------------------------------------------------------------

    201. Midcontinent Joint Consumer Advocates and TAPS oppose 
opportunity cost adders in the verification methodology for cost-based 
incremental energy offers above $1,000/MWh.\435\ Midcontinent Joint 
Consumer Advocates add that if the Commission finds that opportunity 
costs may be recoverable, then the Market Monitoring Unit should review 
such costs to ensure they are just and reasonable.\436\
---------------------------------------------------------------------------

    \435\ Midcontinent Joint Consumer Advocates Comments at 6-7; 
TAPS Comments at 16.
    \436\ Midcontinent Joint Consumer Advocates Comments at 6-7.
---------------------------------------------------------------------------

    202. Commenters expressed a range of opinions regarding whether it 
is appropriate to account for cost uncertainty or other risks through 
an adder in cost-based incremental energy offers above $1,000/MWh. SPP 
takes no position on the appropriateness of the adder but argues that 
the different RTOs/ISOs should be allowed to develop verification rules 
that are consistent with their existing rules, including adders.\437\ 
PJM, MISO, the PJM Market Monitor, and Potomac Economics support an 
adder of up to ten percent to account for uncertainty and risk.\438\ 
The ISO-NE Market Monitor states that the primary function of a ten 
percent adder is to provide for errors or under-estimation of a 
resource's marginal cost and contends that the Commission should not 
require such an adder unless it identifies specific and valid costs 
that are unique to days with abnormally high natural gas prices.\439\
---------------------------------------------------------------------------

    \437\ PJM/SPP Comments at 24.
    \438\ Id. at 22-23; MISO Comments at 15; PJM Market Monitor 
Comments at 9; Potomac Economics Comments at 7.
    \439\ ISO-NE Market Monitor Comments at 12
---------------------------------------------------------------------------

    203. Dominion, Exelon, ODEC, and PJM support the inclusion of a ten 
percent adder to cost-based incremental offers.\440\ Dominion and 
Exelon contend that a ten percent adder to cost-based incremental 
offers is appropriate because the adder accounts for some of the 
uncertainty that accompanies fuel cost estimation as well as dispatch 
instructions.\441\ ODEC maintains that the ten percent adder in cost-
based incremental energy offers is both justified and necessary in PJM 
and should not be removed because it accounts for the fact that some 
costs are unknown when PJM resources compute their cost-based 
incremental energy offers.\442\ APPA, NRECA, and AMP state that adders 
above cost are not necessary when a resource's costs can be accurately 
verified prior to the market clearing process.\443\
---------------------------------------------------------------------------

    \440\ Dominion Comments at 6; Exelon Comments at 20 (citing 
Testimony of Kevin A. Libby at 8-9 (Libby Test.)); ODEC Comments at 
5-6; PJM/SPP Comments at 22.
    \441\ Dominion Comments at 6; Exelon Comments at 20 (citing 
Libby Test. at 8-9).
    \442\ ODEC Comments at 6 (citing PJM 2015 Offer Cap Order, 153 
FERC ] 61,289 at P 30).
    \443\ APPA, NRECA, and AMP Comments at 17.
---------------------------------------------------------------------------

    204. However, the New Jersey Commission, Direct Energy, PG&E, TAPS, 
and Industrial Customers oppose including a ten percent adder in cost-
based incremental energy offers above $1,000/MWh.\444\ The New Jersey 
Commission argues that such an adder would simply afford the generators 
an additional ten percent margin of profit above their costs that 
consumers would fund.\445\ TAPS and Industrial Customers state that the 
ten percent adder should not be included in incremental energy offers 
above $1,000/MWh because the

[[Page 87796]]

adder does not constitute an actual cost.\446\
---------------------------------------------------------------------------

    \444\ Direct Energy Comments at 5; PG&E Comments at 3; New 
Jersey Commission Comments at 17; TAPS Comments at 16; Industrial 
Customers Comments at 25-26 (citing PJM Market Monitor Comments, 
Docket No. ER14-1144, at 2, n. 5 (filed Mar. 26, 2015)).
    \445\ New Jersey Commission Comments at 17.
    \446\ TAPS Comments at 16; Industrial Customers Comments at 25-
26 (citing PJM Market Monitor Comments, Docket No. ER14-1144, at p. 
2, n. 5 (filed Mar. 26, 2015)).
---------------------------------------------------------------------------

    205. With respect to other short-run marginal cost components, the 
Pennsylvania Commission, CAISO, and Industrial Customers argue that a 
resource's permissible short-run marginal costs should not include 
unauthorized natural gas costs and natural gas pipeline penalties.\447\ 
CAISO requests that the Commission convene a technical conference to 
discuss limitations in fuel markets and the appropriate parameters for 
determining prudently incurred costs.\448\ Industrial Customers recount 
the Commission's reasoning that allowing recovery for costs and 
penalties of unauthorized gas consumption could jeopardize gas pipeline 
and transmission system reliability, and that generators would still 
have sufficient flexibility.\449\
---------------------------------------------------------------------------

    \447\ Pennsylvania Commission Comments at 5, 10; CAISO Comments 
at 11-12; Industrial Customers Comments at 26.
    \448\ CAISO Comments at 12.
    \449\ Industrial Customers Comments at 26-27 (citing N.Y. Indep. 
Sys. Operator, Inc., 154 FERC ] 61,111, at P 1 (2016)).
---------------------------------------------------------------------------

    206. The Commission also sought comment on whether the verification 
of physical offer components is necessary.\450\ The ISO-NE Market 
Monitor states that ISO-NE's existing process to verify physical offer 
components takes significant time because such changes to physical 
offer parameters cannot be completed on the day that offers are 
due.\451\ The ISO-NE Market Monitor advises the Commission to avoid 
imposing time limitations that interfere with the ISO-NE Market 
Monitor's ability to review and verify physical parameters before-the-
fact.\452\ The PJM Market Monitor requests that the Commission clarify 
that the cost-based offers contemplated in the NOPR include the same 
limits on offer parameters as all other cost-based offers.\453\ Potomac 
Economics advises that any Final Rule not address physical parameters 
because additional verification of physical parameters is not needed, 
and the proposal only addressed incremental energy offers.\454\ 
Midcontinent Joint Consumer Advocates note that physical offer 
components such as generation minimum and maximum levels are already 
known and reviewed by the Market Monitoring Unit, and therefore, there 
is no need for additional verification of physical offer 
components.\455\
---------------------------------------------------------------------------

    \450\ NOPR, FERC Stats. & Regs. ] 32,714 at P 73.
    \451\ ISO-NE Market Monitor Comments at 10.
    \452\ Id. at 11.
    \453\ PJM Market Monitor Comments at 2-3.
    \454\ Potomac Economics Comments at 11 (citing Potomac Economics 
Post-Technical Workshop Comments. Docket No. AD14-14-000, at 5 
(filed Feb. 24, 2015)).
    \455\ Midcontinent Joint Consumer Advocates Comments at 6.
---------------------------------------------------------------------------

2. Determination
    207. Several commenters state that adders above costs should be 
included in cost-based offers to account for cost uncertainty or 
risk.\456\ While we will not require RTOs/ISOs to include such an 
adder, if an RTO/ISO chooses to retain an adder above cost or proposes 
to include a new adder above cost in cost-based incremental energy 
offers above $1,000/MWh, such adders may not exceed $100/MWh. On 
balance, we find that limiting adders above cost to $100/MWh is just 
and reasonable because as clarified above, the verification process may 
involve reviewing a resource's expected, rather than actual, costs, 
which could involve the use of imperfect information. Given that 
practical reality, we find that it is necessary to place an upper bound 
on the level of adders above cost when incremental energy offers exceed 
$1,000/MWh in order to ensure that cost-based incremental energy offers 
above $1,000/MWh reasonably and accurately reflect actual or expected 
short-run marginal cost.\457\ The Commission has previously found in 
PJM that adders above cost are unjust and unreasonable as applied to an 
after-the-fact review of documented costs because the costs are no 
longer uncertain.\458\ Applying that same reasoning here, if a resource 
receives uplift after-the-fact because that resource's cost-based 
incremental energy offer above $1,000/MWh could not be verified prior 
to the market clearing process or because its cost-based incremental 
energy offer exceeded $2,000/MWh, the uplift payments that the resource 
receives should not include any adders above costs. As noted above, 
after-the-fact uplift would be based on a resource's actual costs.\459\
---------------------------------------------------------------------------

    \456\ See supra P 203.
    \457\ The Commission notes that it previously accepted adders 
above costs in PJM that exceed $100/MWh. However, after reviewing 
the record before us in this proceeding, we find that it is just and 
reasonable to limit the adder to $100/MWh. See PJM 2015 Offer Cap 
Order, 153 FERC ] 61,289 at P 31.
    \458\ PJM 2015 Offer Cap Order, 153 FERC ] 61,289 at P 31 
(citing PJM Interconnection, L.L.C., 149 FERC ] 61,059 at P 13).
    \459\ See supra P 146.
---------------------------------------------------------------------------

    208. Based on the record before us, we will not require that 
additional information on short-run marginal cost components be 
provided to the RTO/ISO or Market Monitoring Unit. Furthermore, we will 
not prescribe the manner in which RTOs/ISOs or Market Monitoring Units 
verify cost-based incremental energy offers above $1,000/MWh. As 
indicated in the NOPR, RTOs/ISOs use different processes to develop and 
update the incremental energy offers used for mitigation and differ in 
how they define the components of cost-based incremental energy 
offers.\460\ While we are taking no action at this time on these issues 
and comments, we do not prejudge what RTOs/ISOs may file with the 
Commission in the future. Accordingly, the Final Rule will not require 
verification of physical offer parameters or financial offer components 
other than the incremental energy offer.
---------------------------------------------------------------------------

    \460\ NOPR, FERC Stats. & Regs. ] 32,714 at PP 61-62.
---------------------------------------------------------------------------

B. Impact of Offer Cap Reforms on Other Market Elements

    209. The Commission recognized in the NOPR that revising the offer 
cap may impact other RTO/ISO market elements that depend on the offer 
cap, such as shortage pricing levels or various penalty factors.\461\
---------------------------------------------------------------------------

    \461\ Id. P 72.
---------------------------------------------------------------------------

1. Comments
    210. Four RTOs/ISOs commented that RTO/ISO market elements other 
than the offer cap may need to be revised if the offer cap is revised. 
CAISO states that it will face significant implementation challenges if 
it changes its current $1,000/MWh offer cap because the administrative 
penalty prices CAISO uses in its market model to indicate that 
constraints have been relaxed, such as the power balance constraint, 
are based on the offer cap.\462\
---------------------------------------------------------------------------

    \462\ CAISO Comments at 14-17. CAISO requests that, prior to 
issuing the Final Rule, the Commission conduct a technical 
conference to better understand the challenges of implementation. 
CAISO Comments at 3, 17.
---------------------------------------------------------------------------

    211. PJM states that it would likely need to adjust shortage 
pricing rules in PJM in light of any Final Rule on offer caps.\463\ SPP 
states that it would likely need to revise its scarcity prices and 
violation relaxation limits to prevent instances in which LMPs exceed 
scarcity values.\464\ MISO states that it may need to revise its 
Operating Reserve Demand Curve, $3,500/MWh LMP cap, and Transmission 
Constraint Demand Curves if MISO's $1,000/MWh offer cap is 
revised.\465\
---------------------------------------------------------------------------

    \463\ PJM/SPP Comments at 28.
    \464\ Id. at 29.
    \465\ MISO Comments at 3-5.
---------------------------------------------------------------------------

    212. APPA, NRECA, and AMP and ODEC state that any Final Rule

[[Page 87797]]

regarding offer caps should be restricted to changing the offer cap and 
not address potentially associated issues such as scarcity 
pricing.\466\ In contrast, PG&E recommends that before allowing the 
offer cap to rise above $1,000/MWh, the Commission and the individual 
RTOs/ISOs should determine all related changes to the markets that 
would be needed to ensure that the markets would function 
properly.\467\
---------------------------------------------------------------------------

    \466\ ODEC Comments at 1; APPA, NRECA, and AMP Comments at 20-
21.
    \467\ PG&E Comments at 2.
---------------------------------------------------------------------------

2. Determination
    213. An RTO/ISO may file, pursuant to section 205 of the Federal 
Power Act, to propose modifications to shortage prices or other market 
elements that require revision in light of the offer cap reforms 
adopted in this Final Rule. However, we do not require such 
modifications to comply with this Final Rule. We find that it is not 
appropriate to determine in this Final Rule the changes that individual 
RTOs/ISOs should make to market elements that are not the subject of 
these reforms.

VII. Requests Beyond the Scope of This Proceeding

A. Comments

    214. Commenters raised issues that are not discussed above and that 
are outside the scope of this rulemaking. Several commenters argue that 
the focus of the recommendations in the NOPR is too narrow. API 
recommends that the Commission look for ways to encourage the 
appropriate integration of new technologies, including quickly ramping 
gas-fired generation technology, to meet rapidly changing grid-
conditions and allow prices in real-time markets to better reflect the 
true state of grid reliability at a given moment while addressing any 
remaining concerns of market power abuse.\468\ API further recommends 
that the Commission initiate an examination of opportunity costs and 
risk premiums, inclusive of a wider range of resources, in wholesale 
energy market offer pricing and how they may or may not be considered 
by various RTO/ISO market rules.\469\
---------------------------------------------------------------------------

    \468\ API Comments at 2-3.
    \469\ Id. at 8.
---------------------------------------------------------------------------

    215. The PJM Market Monitor argues that because gas is the only 
fuel likely to result in offers greater than $1,000/MWh, the removal of 
any cap on short run marginal cost therefore relies on the 
competitiveness of the gas markets.\470\ The PJM Market Monitor 
suggests that a reconsideration of the structure and design of the gas 
market and the potential for a gas market RTO/ISO is a longer term 
solution to address issues of transparency and market power in the gas 
market.\471\
---------------------------------------------------------------------------

    \470\ PJM Market Monitor Comments at 4.
    \471\ Id. at 6.
---------------------------------------------------------------------------

    216. The Pennsylvania Commission states that the Commission should 
direct PJM and other RTO/ISO stakeholders to develop a ``circuit 
breaker'' provision to cap energy market revenue during uncontrollable 
and sustained outage events.\472\ The Pennsylvania Commission states 
that during sustained outages, price signals in energy markets become 
irrelevant, and the main consideration is the time required to repair 
infrastructure as opposed to the economic theory behind energy 
markets.\473\ The Pennsylvania Commission also recommends that the 
Commission direct PJM to introduce some level of aggregate market power 
mitigation or impose a screen for aggregate market power in the PJM 
day-ahead and real-time markets.\474\ PJM Joint Consumer Advocates 
argue that shortage prices in PJM should be revised to represent 
customers' willingness to pay,\475\ and the Ohio Commission states that 
scarcity pricing may no longer be necessary in light of this Final 
Rule.\476\
---------------------------------------------------------------------------

    \472\ Pennsylvania Commission Comments at 5-7.
    \473\ Id. at 8.
    \474\ Id. at 13-14.
    \475\ PJM Joint Consumer Advocates Comments at 5-6.
    \476\ Ohio Commission Comments at 14-15.
---------------------------------------------------------------------------

    217. Industrial Customers argue that increases to the current 
$1,000/MWh offer cap should be explored simultaneously with the 
elimination of capacity markets, and that the Commission could act more 
methodically to explore ways to improve capacity market competitiveness 
and transparency.\477\
---------------------------------------------------------------------------

    \477\ Industrial Customers Comments at 29-30.
---------------------------------------------------------------------------

B. Determination

    218. We appreciate the concerns raised by numerous commenters 
requesting that the Commission undertake various initiatives, as set 
forth above. However, we find that the requested initiatives go beyond 
the scope of this rulemaking, which only addresses incremental energy 
offers above $1,000/MWh. Accordingly, we will not address those 
concerns here.

VIII. Information Collection Statement

    219. The Paperwork Reduction Act (PRA) \478\ requires each federal 
agency to seek and obtain Office of Management and Budget (OMB) 
approval before undertaking a collection of information directed to ten 
or more persons or contained in a rule of general applicability. OMB's 
regulations,\479\ in turn, require approval of certain information 
collection requirements imposed by agency rules. Upon approval of a 
collection(s) of information, OMB will assign an OMB control number and 
an expiration date. Respondents subject to the filing requirements of a 
rule will not be penalized for failing to respond to these 
collection(s) of information unless the collection(s) of information 
display a valid OMB control number.
---------------------------------------------------------------------------

    \478\ 44 U.S.C. 3501-3520.
    \479\ 5 CFR 1320 (2016).
---------------------------------------------------------------------------

    220. In this Final Rule, we are amending the Commission's 
regulations to improve the operation of organized wholesale electric 
power markets operated by RTOs/ISOs. We require that each RTO/ISO (1) 
cap each resource's incremental energy offer at the higher of $1,000/
MWh or that resource's verified cost-based incremental energy offer; 
and (2) when calculating LMPs, RTOs/ISOs shall cap verified cost-based 
incremental energy offers at $2,000/MWh. The reforms required in this 
Final Rule would require a one-time tariff filing with the Commission 
due 75 days after the effective date of this Final Rule to implement 
these reforms. We anticipate the reforms required in this Final Rule, 
once implemented, would not significantly change currently existing 
burdens on an ongoing basis. With regard to those RTOs/ISOs that 
believe that they already comply with the reforms required in this 
Final Rule, they could demonstrate their compliance in the compliance 
filing required 75 days after the effective date of this Final Rule in 
this proceeding. The Commission will submit the proposed reporting 
requirements to OMB for its review and approval under section 3507(d) 
of the Paperwork Reduction Act.\480\
---------------------------------------------------------------------------

    \480\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    221. In the NOPR, the Commission sought comments on the accuracy of 
provided burden and cost estimates and any suggested methods for 
minimizing the respondents' burdens, including the use of automated 
information techniques. Specifically, the Commission sought detailed 
comments on the potential cost and time necessary to implement aspects 
of the reforms proposed in the NOPR, including (1) software and 
business processes changes, including market power mitigation; (2) 
increased time spent validating cost-based incremental energy offers; 
and (3) processes for RTOs/ISOs to vet proposed changes amongst their 
stakeholders. The Commission also stated that although it did not 
expect other entities to incur

[[Page 87798]]

compliance costs as a result of the reforms proposed in the NOPR, it 
sought detailed comments on whether other entities, such as load-
serving entities, would incur costs as a result of the reforms proposed 
in the NOPR. The Commission received no comments in response to these 
questions.
    Burden Estimate and Information Collection Costs: The Commission 
believes that the burden estimates below are representative of the 
average burden on respondents, including necessary communications with 
stakeholders. The estimated burden and cost for the requirements 
contained in this rule follow.\481\ The Commission notes that these 
cost estimates below do not include costs for software or hardware or 
for increased time spent validating cost-based incremental energy 
offers above $1,000/MWh.\482\ Software or hardware upgrades may not be 
required.
---------------------------------------------------------------------------

    \481\ The RTOs/ISOs (CAISO, ISO-NE., MISO, NYISO, PJM, and SPP) 
are required to comply with the reforms in this Final Rule.
    \482\ The Commission expects that the validation of cost-based 
incremental energy offers above $1,000/MWh would be an infrequent 
occurrence. To the extent that the Market Monitoring Unit or the 
RTO/ISO spends time validating these offers, the Commission 
estimates such time to be de minimis.

                                                FERC-516, as Modified by Final Rule in Docket RM16-5-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                Annual number
                                 Number of       of responses     Total number   Average  burden  (hours) &  Total annual  burden hours      Cost per
                                respondents    per  respondent    of responses        cost per  response         & total  annual cost    respondent  ($)
                                         (1)              (2)   (1) x (2) = (3)  (4).......................  (3) x (4) = (5)...........       (5) / (1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
One-Time Tariff Filings                    6                1                6   500 hrs.; $37,000 \483\...  3,000 hrs.; $222,000......         $37,000
 (Year 1).
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the total cost of 
compliance, all within four months of a Final Rule plus initial 
implementation, to be $222,000. After Year 1, the reforms in this Final 
Rule, once implemented, would not significantly change existing burdens 
on an ongoing basis.
---------------------------------------------------------------------------

    \483\ The estimated hourly cost (salary plus benefits) provided 
in this section is based on the salary figures for May 2015 posted 
by the Bureau of Labor Statistics for the Utilities sector 
(available at http://www.bls.gov/oes/current/naics2_22.htm#13-0000) 
and scaled to reflect benefits using the relative importance of 
employer costs in employee compensation from June 2016 (available at 
http://www.bls.gov/news.release/ecec.nr0.htm). The hourly estimates 
for salary plus benefits are:
     Legal (code 23-0000), $128.94
     Computer and mathematical (code 15-0000), $60.54
     Information systems manager (code 11-3021), $91.63
     IT security analyst (code 15-1122), $63.55
     Auditing and accounting (code 13-2011), $53.78
     Information and record clerk (code 43-4199), $37.69
     Electrical Engineer (code 17-2071), $64.20
     Economist (code 19-3011), $74.43
     Management (code 11-0000), $88.94
    The average hourly cost (salary plus benefits), weighting all of 
these skill sets evenly, is $73.74. The Commission rounds it to $74 
per hour.
---------------------------------------------------------------------------

    The Commission notes that these estimates do not include costs for 
software or hardware. Software or hardware upgrades may not be 
required.
    Title: FERC-516C,\484\ Electric Rate Schedules and Tariff Filings.
---------------------------------------------------------------------------

    \484\ The RM16-5-000 Final Rule reporting requirements should be 
submitted to FERC-516 (OMB Control No. 1902-0096). Currently, that 
information collection is under review for an unrelated activity. 
The FERC-516C is a temporary information collection. The reporting 
requirements of the RM16-5-000 Final Rule are being submitted to 
FERC-516C to ensure timely submission to OMB.
---------------------------------------------------------------------------

    Action: Proposed revisions to an information collection.
    OMB Control No. 1902-0287.
    Respondents for this Rulemaking: RTOs/ISOs.
    Frequency of Information: One-time.
    Necessity of Information: The Federal Energy Regulatory Commission 
approves this rule to improve competitive wholesale electric markets in 
the RTO/ISO regions.
    Internal Review: The Commission has reviewed the changes and has 
determined that such changes are necessary. These requirements conform 
to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has specific, objective support for the burden estimates 
associated with the information collection requirements.
    222. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director], email: 
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 
Comments concerning the collection of information and the associated 
burden estimate(s), may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission, phone: (202) 395-0710, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically 
to the following email address: oira_submission@omb.eop.gov. Comments 
submitted to OMB should include FERC-516C and OMB Control No. 1902-
0287.

IX. Regulatory Flexibility Act Certification

    223. The Regulatory Flexibility Act of 1980 (RFA) \485\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities. The RFA does 
not mandate any particular outcome in a rulemaking. It only requires 
consideration of alternatives that are less burdensome to small 
entities and an agency explanation of why alternatives were rejected.
---------------------------------------------------------------------------

    \485\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

    224. This rule would apply to six RTOs/ISOs (all of which are 
transmission organizations). The average estimated annual cost to each 
of the RTOs/ISOs is $37,000, all in Year 1. This one-time cost of 
filing and implementing these changes is not significant.\486\ 
Additionally, the RTOs/ISOs are not small entities, as defined by the 
RFA.\487\ This is because the

[[Page 87799]]

relevant threshold between small and large entities is 500 employees 
and the Commission understands that each RTO/ISO has more than 500 
employees. Furthermore, because of their pivotal roles in wholesale 
electric power markets in their regions, none of the RTOs/ISOs meet the 
last criterion of the two-part RFA definition a small entity: ``not 
dominant in its field of operation.'' As a result, we certify that the 
reforms in this Final Rule would not have a significant economic impact 
on a substantial number of small entities.
---------------------------------------------------------------------------

    \486\ This estimate does not include costs for software or 
increased time spent validating cost-based incremental energy 
offers. As stated above, the Commission expects that the validation 
of cost-based incremental energy offers above $1,000/MWh would be an 
infrequent occurrence. To the extent that the Market Monitoring Unit 
or the RTO/ISO spends time validating these offers, the Commission 
expects such time to be de minimis.
    \487\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
Small Business Administrations' regulations at 13 CFR 121.201 define 
the threshold for a small Electric Bulk Power Transmission and 
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 
632.
---------------------------------------------------------------------------

X. Environmental Analysis

    225. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\488\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Final Rule under 
section 380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the Federal Power Act relating to the filing of schedules 
containing all rates and charges for the transmission or sale of 
electric energy subject to the Commission's jurisdiction, plus the 
classification, practices, contracts and regulations that affect rates, 
charges, classifications, and services.\489\
---------------------------------------------------------------------------

    \488\ Regulations Implementing the National Environmental Policy 
Act of 1989, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC 
Stats. & Regs. ] 30,783 (1987).
    \489\ 18 CFR 380.4(a)(15) (2016).
---------------------------------------------------------------------------

XI. Document Availability

    226. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington, DC 20426.
    227. From the Commission's Home Page on the Internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number of this document, excluding the last three digits, in 
the docket number field.
    228. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

XII. Effective Date and Congressional Notification

    229. These regulations are effective February 21, 2017. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Non-discriminatory open 
access transmission tariffs.

    By the Commission.

    Issued: November 17, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
    In consideration of the foregoing, the Commission amends part 35, 
chapter I, title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

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


0
2. Amend Sec.  35.28 by adding paragraph (g)(9) to read as follows:


Sec.  35.28   Non-discriminatory open access transmission tariff.

* * * * *
    (g) * * *
    (9) 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. 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. All resources, regardless of type, are eligible to 
submit cost-based incremental energy offers in excess of $1,000/MWh.
    The following appendix will not appear in the Code of Federal 
Regulations.

          Appendix--List of Short Names/Acronyms of Commenters
------------------------------------------------------------------------
        Short name/acronym                        Commenter
------------------------------------------------------------------------
AEMA..............................  Advanced Energy Management Alliance.
AF&PA.............................  American Forest & Paper Association.
APPA, NRECA, and AMP..............  American Public Power Association,
                                     National Rural Electric Cooperative
                                     Association and American Municipal
                                     Power, Inc.
API...............................  American Petroleum Institute.
CAISO.............................  California Independent System
                                     Operator Corporation.
CEA...............................  Canadian Electricity Association.
Competitive Suppliers.............  Electric Power Supply Association,
                                     Independent Energy Producers
                                     Association, Independent Power
                                     Producers of New York Inc., New
                                     England Power Generators
                                     Association Inc., Western Power
                                     Trading Forum.
Delaware Commission...............  Delaware Public Service Commission.

[[Page 87800]]

 
Direct Energy.....................  Direct Energy Business, LLC, on
                                     behalf of itself and its affiliate,
                                     Direct Energy Business Marketing,
                                     LLC.
Dominion..........................  Dominion Resources Services, Inc.
EEI...............................  Edison Electric Institute.
Exelon............................  Exelon Corporation.
Golden Spread.....................  Golden Spread Electric Cooperative,
                                     Inc.
Industrial Customers..............  Electricity Consumers Resource
                                     Council, PJM Industrial Customer
                                     Coalition, Coalition of MISO
                                     Transmission Customers, American
                                     Chemistry Council, Association of
                                     Businesses Advocating Tariff
                                     Equity, Connecticut Industrial
                                     Energy Consumers, Illinois
                                     Industrial Energy Consumers,
                                     Indiana Industrial Energy
                                     Consumers, Inc., Louisiana Energy
                                     Users Group, Minnesota Large
                                     Industrial Group, Missouri
                                     Industrial Energy Consumers,
                                     Multiple Intervenors, New Jersey
                                     Large Energy Users Coalition,
                                     Wisconsin Industrial Energy Group,
                                     Inc.
Industrial Energy Consumers.......  Industrial Energy Consumers of
                                     America.
ISO-NE............................  ISO New England, Inc.
ISO-NE Market Monitor.............  ISO New England Inc. Internal Market
                                     Monitor.
IRC...............................  ISO/RTO Council.
KEPCo/NCEMC.......................  Kansas Electric Power Cooperative,
                                     Inc. and North Carolina Electric
                                     Membership Corporation.
Joseph Margolies..................  Joseph Margolies.
Midcontinent Joint Consumer         Indiana Office of Utility Consumer
 Advocates.                          Counselor, Iowa Office of Consumer
                                     Advocate, Michigan Citizens Against
                                     Rate Excess, Minnesota Department
                                     of Commerce, Minnesota Attorney
                                     General's Office.
MISO..............................  Midcontinent Independent System
                                     Operator, Inc.
NEI...............................  Nuclear Energy Institute.
NESCOE............................  New England States Committee on
                                     Electricity.
New Jersey Commission.............  New Jersey Board of Public
                                     Utilities.
NY Department of State............  New York State Department of State
                                     Utility Intervention Unit.
NYISO.............................  New York Independent System
                                     Operator, Inc.
New York Commission...............  New York State Public Service
                                     Commission.
NY Transmission Owners............  New York Transmission Owners
                                     (Central Hudson Gas & Electric
                                     Corporation, Consolidated Edison
                                     Company of New York, Inc., New York
                                     Power Authority, New York State
                                     Electric & Gas Corporation, Niagara
                                     Mohawk Power Corporation d/b/a
                                     National Grid, Orange and Rockland
                                     Utilities, Inc., Power Supply Long
                                     Island, Rochester Gas and Electric
                                     Corporation).
ODEC..............................  Old Dominion Electric Cooperative.
OMS...............................  Organization of MISO States.
OPSI..............................  Organization of PJM States, Inc.
Pennsylvania Commission...........  Pennsylvania Public Utility
                                     Commission.
PG&E..............................  Pacific Gas and Electric Company.
PJM/SPP...........................  PJM Interconnection, L.L.C. and
                                     Southwest Power Pool, Inc. (Joint
                                     Comments).
PJM Joint Consumer Advocates......  Delaware Division of the Public
                                     Advocate, Office of People's
                                     Counsel for the District of
                                     Columbia, Illinois Citizens Utility
                                     Board, Indiana Office of Utility
                                     Consumer Counselor, Kentucky Office
                                     of Rate Intervention, Office of
                                     Attorney General, Maryland Office
                                     of Peoples' Counsel, New Jersey
                                     Division of Rate Counsel,
                                     Pennsylvania Office of Consumer
                                     Advocate, Consumer Advocate
                                     Division of the Public Service
                                     Commission of West Virginia.
PJM Market Monitor................  Monitoring Analytics, LLC, acting in
                                     its capacity as the Independent
                                     Market Monitor for PJM.
PJM Power Providers...............  PJM Power Providers Group.
Potomac Economics.................  Potomac Economics, Ltd.
Powerex...........................  Powerex Corp.
Ohio Commission...................  Public Utilities Commission of Ohio.
SCE...............................  Southern California Edison Company.
Six Cities........................  Cities of Anaheim, Azusa, Banning,
                                     Colton, Pasadena, and Riverside,
                                     California.
SPP...............................  Southwest Power Pool, Inc.
SPP Market Monitor................  Southwest Power Pool, Inc. Market
                                     Monitoring Unit.
Steel Producers' Alliance.........  Steel Producers' Alliance.
TAPS..............................  Transmission Access Policy Study
                                     Group.
------------------------------------------------------------------------

[FR Doc. 2016-28320 Filed 12-2-16; 8:45 am]
 BILLING CODE 6717-01-P