82 FR 53403 - Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission Federal Register Volume 82, Issue 220 (November 16, 2017)
Federal Energy Regulatory Commission
Federal Register Volume 82, Issue 220 (November 16, 2017)
| Page Range | 53403-53411 | |
| FR Document | 2017-24803 |
[Federal Register Volume 82, Number 220 (Thursday, November 16, 2017)] [Rules and Regulations] [Pages 53403-53411] From the Federal Register Online [www.thefederalregister.org] [FR Doc No: 2017-24803] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM16-5-001; Order No. 831-A] Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators AGENCY: Federal Energy Regulatory Commission, Department of Energy. ACTION: Order on rehearing and clarification. ----------------------------------------------------------------------- SUMMARY: The Federal Energy Regulatory Commission is granting in part and denying in part requests for rehearing and clarification of its determinations in Order No. 831, which amended its regulations to address incremental energy offer caps in markets operated by regional transmission organizations and independent system operators. DATES: This rule is effective January 16, 2018. 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, [email protected] Pamela Quinlan (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6179, [email protected] Anne Marie Hirschberger (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8387, [email protected] SUPPLEMENTARY INFORMATION: Table of Contents Paragraph Nos. I. Introduction...................................... 1 II. Discussion....................................... 5 A. Offer Cap Structure........................... 5 1. Hard Cap Level............................ 6 2. Implementation of the Hard Cap............ 13 B. Verification Requirement...................... 18 1. Expected Costs............................ 19 2. Verification of Imports................... 30 C. Costs Included in Cost-Based Incremental 34 Energy Offers................................... 1. Requests for Rehearing/Clarification...... 34 2. Determination............................. 37 III. Information Collection Statement................ 41 IV. Regulatory Flexibility Act Certification......... 44 V. Document Availability............................. 45 VI. Effective Date................................... 48 I. Introduction 1. On November 17, 2016, the Federal Energy Regulatory Commission (Commission) issued Order No. 831.\1\ Order No. 831 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 are one of the components used to calculate locational marginal prices (LMPs). California Independent System Operator Corporation (CAISO), ISO New England Inc. (ISO-NE), Midcontinent Independent System Operator, Inc. (MISO), New York Independent System Operator, Inc. (NYISO), and Southwest Power Pool, Inc. (SPP) currently have a $1,000/ MWh cap on incremental energy offers (offer cap), and PJM Interconnection, L.L.C. (PJM) currently has an offer cap of $2,000/MWh on cost-based offers.\2\ --------------------------------------------------------------------------- \1\ Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, 81 FR 87,770 (Dec. 5, 2016), FERC Stats. & Regs. ] 31,387 (2016) (Order No. 831). \2\ Order No. 831, FERC Stats. & Regs. ] 31,387 at PP 11-13. --------------------------------------------------------------------------- 2. In Order No. 831, the Commission amended its regulations to require that each regional transmission organization and independent system operator (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) cap verified cost-based incremental energy offers at $2,000/MWh when calculating LMPs (hard cap).\3\ Resources with verified cost-based incremental energy offers above $2,000/MWh will be eligible to receive uplift.\4\ In response to comments on the Notice of Proposed [[Page 53404]] Rulemaking,\5\ the Commission clarified that each RTO/ISO or Market Monitoring Unit must verify that any incremental energy offer above $1,000/MWh reasonably reflects the associated resource's actual or expected costs, as opposed to only the resource's actual costs, prior to using that offer to calculate LMP.\6\ --------------------------------------------------------------------------- \3\ Id. P 1. \4\ Id. P 78. \5\ 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 PP 3 (2016) (NOPR). \6\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 139. --------------------------------------------------------------------------- 3. With respect to treatment of cost-based incremental energy offers above $2,000/MWh, the Commission stated that it expects RTOs/ ISOs to use such offers to determine merit-order dispatch, and it cited PJM as an example of an RTO/ISO that 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 LMP.\7\ The Commission found that imports should be permitted to offer above $1,000/MWh, but will not be subject to verification.\8\ Finally, while Order No. 831 did not require RTOs/ISOs to include an adder above cost in cost-based incremental energy offers above $1,000/MWh, the Commission stated that if an RTO/ISO chooses to retain existing rules that allow for an adder above cost or proposes any new adders above cost, such adders may not exceed $100/MWh.\9\ However, in Order No. 831, the Commission did not require RTOs/ISOs to change the costs they currently include in cost-based incremental energy offers, and it did not address whether verifiable opportunity costs are subject to the $100/MWh limit on adders. --------------------------------------------------------------------------- \7\ Id. P 90. \8\ Id. P 192. \9\ Id. P 207. --------------------------------------------------------------------------- 4. On December 19, 2016, the Commission received four requests for rehearing and/or clarification of Order No. 831 which raise issues related to the structure of the offer cap, the verification requirement, and the costs included in cost-based incremental energy offers. TAPS filed a request for rehearing and clarification. NYISO filed a request for clarification and, alternatively, request for rehearing. AMP/APPA filed a request for rehearing. Exelon filed a motion for clarification and request for rehearing.\10\ For the reasons discussed below, we grant in part and deny in part the requests for rehearing and clarification. --------------------------------------------------------------------------- \10\ The Independent Market Monitor for PJM (PJM Market Monitor) filed an answer to Exelon's motion for clarification and request for rehearing. MISO filed comments in support of NYISO's request for clarification and, alternatively, request for rehearing. Rule 713(d)(1) of the Commission's Rules of Practice and Procedure prohibits answers to requests for rehearing. 18 CFR 385.713(d)(2) (2017). We therefore reject the answer of the PJM Market Monitor. We will treat MISO's comments as an answer and as a result reject them. --------------------------------------------------------------------------- II. Discussion A. Offer Cap Structure 5. The requests for rehearing and clarification regarding the offer cap structure focus on the level of the hard cap and the implementation of the hard cap. 1. Hard Cap Level a. Request for Rehearing 6. TAPS seeks rehearing and argues both that the $2,000/MWh hard cap level established by the Commission is not supported by substantial evidence, and that the $1,724/MWh offer cited in Order No. 831 was not a legitimate cost-based incremental energy offer.\11\ Rather, TAPS states, the $1,724/MWh offer was the estimated cost of a resource calculated according to PJM's Cost Development Guidelines, but the actual cost of that resource was less than $1,500/MWh. TAPS argues that, given the large discrepancy between estimated and actual costs, it was inappropriate for the Commission to rely on an estimated $1,724/ MWh offer as the basis for the $2,000/MWh hard cap level. TAPS asserts that, even if it was appropriate for the Commission to rely upon estimated costs, the Commission should not have used the $1,724/MWh level, since it was estimated using a methodology that is not compliant with Order No. 831. TAPS contends that the Commission should instead set the hard cap level at $1,500/MWh or, alternatively, at $1,800/MWh if the Commission determines that there was a legitimate cost-based incremental energy offer of $1,724/MWh.\12\ TAPS also argues that the Commission failed to meaningfully address the analytical evidence TAPS presented in its comments supporting a $1,500/MWh hard cap.\13\ --------------------------------------------------------------------------- \11\ TAPS Request for Clarification/Rehearing at 2 (citing Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315 (D.C. Cir. 2004); Canadian Ass'n of Petroleum Producers v. FERC, 254 F.3d 289 (D.C. Cir. 2001) (Canadian Ass'n of Petroleum Producers)). \12\ Id. at 5-11. \13\ Id. at 10 (citing Canadian Ass'n of Petroleum Producers, 254 F.3d at 299 (an agency's ``failure to respond meaningfully'' to objections raised by a party renders its decision arbitrary and capricious)). --------------------------------------------------------------------------- b. Determination 7. We deny TAPS' request for rehearing of the $2,000/MWh level of the hard cap. In Order No. 831, the Commission determined that a hard cap was necessary to limit any adverse impact on LMPs due to imperfect information about a resource's short-run marginal costs that might arise during the verification process.\14\ The Commission also recognized that a hard cap that is too low might suppress LMPs below the marginal cost of production.\15\ In determining the $2,000/MWh level of the hard cap, the Commission therefore struck a balance between competing goals: (1) Limiting any adverse impacts on LMPs due to imperfect information during the verification process and (2) reducing the likelihood of suppressing LMPs below the marginal cost of production. --------------------------------------------------------------------------- \14\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 87. \15\ Id. P 91. --------------------------------------------------------------------------- 8. The overall offer cap structure set forth in Order No. 831 and the overall market structure of RTOs/ISOs in which the offers arise affected the balance struck by the Commission in setting the level of the hard cap. The hard cap does not stand alone, meaning that it is not the only way of ensuring that an offer does not reflect the exercise of market power and that the price resulting from an incremental energy offer is just and reasonable. In balancing the competing goals, the Commission effectively recognized that the hard cap serves as a backstop to the mitigation established through both the cost-based requirement and the verification process--the other elements of the offer cap structure. The cost-based offer requirement serves a ``mitigation function'' \16\ by requiring incremental energy offers above $1,000/MWh be cost-based. The verification requirement also addresses market power concerns.\17\ The hard cap ``limit[s] the adverse impact that any imperfect information about resources' short- run marginal costs during the verification process could have on LMPs.'' \18\ The Commission factored in these two other elements of the offer-cap structure in balancing the competing goals to set the level of the hard cap. --------------------------------------------------------------------------- \16\ Id. P 83. \17\ Id. P 139. \18\ Id. P 87. --------------------------------------------------------------------------- 9. In setting that level, the Commission also considered the overall market structure of RTOs/ISOs--a structure designed to ensure that markets are competitive and not subject to the exercise of market power, through for instance, existing market power mitigation processes.\19\ The hard cap [[Page 53405]] also serves as backstop to those existing market mitigation processes.\20\ --------------------------------------------------------------------------- \19\ Cf. id. PP 85-90. Additionally, all six RTOs/ISOs have market power mitigation rules designed to prevent market participants from exercising market power. See, e.g., California Independent System Operator Corporation, eTariff, 39; ISO New England Inc., Markets and Services Tariff, Market Rule 1, Appendix A; Midcontinent Independent System Operator, Inc., FERC Electric Tariff, Module D; New York Independent System Operator, Inc., Market Administration and Control Area Services Tariff, Attachment H; PJM Interconnection, L.L.C., Intra-PJM Tariffs, OATT, Tariff Operating Agreement, Attachment M; and Southwest Power Pool, Inc., OATT, Sixth Revised Volume No. 1, Attachment AF. \20\ Cf. id. P 89. --------------------------------------------------------------------------- 10. Based on the record, the Commission set the level of the hard cap to $2,000/MWh. The Commission determined that $2,000/MWh was the level that short-run marginal costs would rarely exceed.\21\ The cost- based incremental energy offer of $1,724/MWh referenced in Order No. 831, and which TAPS questions, regardless of the methodology by which it was derived, was only one point of reference for the Commission within the context of the broader record. Specifically, the Commission also examined the evidence in the record regarding high natural gas prices that occurred during the Polar Vortex when some resources experienced short-run marginal costs above $1,000/MWh.\22\ --------------------------------------------------------------------------- \21\ See id. n.200 (citing 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. FERC, 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)))). \22\ Id. P 92. --------------------------------------------------------------------------- 11. The alternative $1,500/MWh and $1,800/MWh hard cap levels that TAPS proposed would result in a balance different than the one chosen by the Commission. Lower hard cap levels such as these would increase the likelihood of suppressing prices below the marginal cost of production and would thereby run contrary to the Commission's price formation efforts to ensure that LMPs reflect the short-run marginal cost of the marginal resource. We therefore reject TAPS' request for rehearing and the alternative hard cap levels proposed. As stated above, we continue to find that the $2,000/MWh hard cap reasonably balances reducing the likelihood of suppressing LMPs while limiting any adverse impact on LMPs from imperfect information about resources' short-run marginal costs during the verification process. 12. Further, we reject TAPS' argument that the Commission failed to meaningfully address its $1,500/MWh alternative proposal. The Commission addressed this alternative in adopting the $2,000/MWh hard cap.\23\ In any event, in a rulemaking, the Commission need not respond to every comment or analyze every alternative. Rather, the Commission must respond to ``comments which, if true. . .would require a change in an agency's proposed rule.'' \24\ The Commission's determination regarding the $2,000/MWh hard cap is not invalidated merely because there may be a reasonable alternative.\25\ --------------------------------------------------------------------------- \23\ Id. \24\ American Min. Congress v. EPA, 907 F.2d 1179, 1187-88 (D.C. Cir. 1990) (American Min. Congress) (citing Thompson v. Clark, 741 F.2d 401, 408 (D.C. Cir. 1984) (Thompson); ACLU v. FCC, 823 F.2d 1554, 1581 (D.C. Cir.1987) (ACLU)). \25\ See United Distribution Cos. v. FERC, 88 F.3d 1105, 1169-70 (D.C. Cir. 1996) (United Distribution Cos.) (``FERC correctly counters that the fact that AEPCO may have proposed a reasonable alternative . . . is not compelling. The existence of a second reasonable course of action does not invalidate an agency's determination.''). --------------------------------------------------------------------------- 2. Implementation of the Hard Cap a. Requests for Rehearing/Clarification 13. NYISO seeks clarification that Order No. 831 does not require that incremental energy offers above $2,000/MWh be used to determine merit-order dispatch in all RTOs/ISOs, and, in the alternative, seeks rehearing on this issue.\26\ NYISO states that, to the extent the Commission intended to establish a requirement, the Commission did not seek comment on the requirement in the NOPR, did not demonstrate that the requirement must be imposed on all RTOs/ISOs in order to ensure just and reasonable rates, and did not consider the burdens the requirement would impose on NYISO.\27\ --------------------------------------------------------------------------- \26\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at P 90 (``With respect to the 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. . . .'' ''). \27\ NYISO Request for Clarification/Rehearing at 5, 11-13. --------------------------------------------------------------------------- 14. NYISO asserts that such a requirement would introduce foreign market design elements into NYISO that were developed by PJM to be compatible with its own pricing method, market rules, and software.\28\ Specifically, NYISO explains that PJM's design accommodates discrepancies between schedules and price, using a secondary ex post process to determine LMPs that is separate from the process for determining resource schedules. However, NYISO states that it uses a common ex ante process to determine both locational based marginal prices (LBMPs) and resource schedules. NYISO asserts that, because its process utilizes the same offers for scheduling and pricing, it would be challenging to allow resources to be committed and scheduled based on validated incremental energy offers above $2,000/MWh, but then cap the offers for purposes of calculating LBMPs and ancillary services prices. According to NYISO, this would require resource-intensive and potentially costly software changes, make validation of prices and schedules more complex, and require NYISO to redirect resources from other efforts that are more certain to benefit consumers and markets. Additionally, NYISO contends that implementing an offer cap that only limits the offer prices used to determine LBMPs can lead to a divergence between resource schedules and prices that can harm market participants.\29\ --------------------------------------------------------------------------- \28\ NYISO also maintains that RTOs/ISOs do not need to have identical software or market rules, and that the practical ability to implement software changes justifies accommodating regional circumstances. Id. at 6 (citing N.Y. Indep. Sys. Operator, Inc., 142 FERC ] 61,202, at PP 24-26 (2013); N.Y. Indep. Sys. Operator, Inc., 133 FERC ] 61,246, at P 25 (2010)). \29\ Id. at 7-11. --------------------------------------------------------------------------- 15. In addition, NYISO requests clarification that RTOs/ISOs are permitted to apply the same offer cap to both incremental energy and minimum generation offers,\30\ and in the alternative seeks rehearing on this issue. Currently, NYISO's tariff applies a $1,000/MWh offer cap to all day-ahead and real-time energy offers, including minimum generation offers. NYISO argues that applying different offer caps to incremental energy offers and minimum generation offers could incentivize suppliers to artificially shape their offers to conform to the different offer caps rather than offer in a manner that accurately reflects a resource's costs, which would result in less optimal commitment, dispatch, and pricing. Furthermore, NYISO states that if minimum generation offer caps are lower than incremental energy offer caps, generators may not offer to supply energy if they do not expect to be able to recoup their costs.\31\ NYISO also states that the Commission previously granted waiver of the $1,000/MWh offer cap on both incremental energy offers and minimum generation offers in [[Page 53406]] response to spikes in natural gas costs caused by the Polar Vortex.\32\ --------------------------------------------------------------------------- \30\ In NYISO, the first block in a resource's incremental energy offer is called a ``minimum generation bid'' and includes the costs a resource incurs to operate at its economic minimum operating level. NYISO, Manual 11--Day-Ahead Scheduling Manual, Sec. 4.3.3. (October 2016) http://www.nyiso.com/public/webdocs/markets_operations/documents/Manuals_and_Guides/Manuals/Operations/dayahd_schd_mnl.pdf. \31\ NYISO Request for Clarification/Rehearing at 13-15. \32\ Id. at 13 (citing N.Y. Indep. Sys. Operator, Inc., 146 FERC ] 61,061, at PP 2-4, 20 (2014)). --------------------------------------------------------------------------- b. Determination 16. Regarding NYISO's concerns on economic merit-order dispatch, we clarify that Order No. 831 did not require cost-based incremental energy offers above $2,000/MWh to be used to determine economic merit- order dispatch. We recognize that some RTO's/ISO's existing commitment, dispatch, and pricing algorithms are structured differently, and the Commission in Order No. 831 did not require RTOs/ISOs to change their current practices or software to use cost-based incremental energy offers above $2,000/MWh for determining economic merit-order dispatch. However, in the event that RTOs/ISOs must select from several offers above $2,000/MWh, we encourage RTOs/ISOs to make those selections on a least-cost basis when possible, in order to minimize the cost to serve load. 17. We also clarify that application of the offer cap and verification requirement adopted in Order No. 831 to minimum generation offers, as NYISO requests, is appropriate. Applying different offer caps to minimum generation and incremental energy offers could give resources the incentive to shape their offers in a manner that does not reflect their costs.\33\ Furthermore, this application is consistent with prior Commission orders regarding NYISO's offer cap discussed above.\34\ --------------------------------------------------------------------------- \33\ See id. at 14. \34\ See supra P 15. --------------------------------------------------------------------------- B. Verification Requirement 18. The requests for rehearing regarding the verification requirement focus on the use of expected costs in the verification requirement and whether to subject imports to the verification requirement. 1. Expected Costs 19. The requests for rehearing regarding expected costs include the definition of expected costs and whether they should be included in the regulatory text as well as market power concerns related to the use of expected costs in the verification process. a. Definition and Regulatory Text i. Requests for Rehearing 20. AMP/APPA seek rehearing of Order No. 831, arguing that the Commission was arbitrary and capricious because it failed to provide a reasonable justification for allowing sellers' expected costs to set LMP, and that the Commission also unjustifiably expanded the definition of cost-based offers to include ``expected'' costs. According to AMP/ APPA, in order for LMPs to send accurate signals regarding the actual cost of producing energy, LMPs should be based on actual costs. AMP/ APPA argue that, since some commenters stated that pre-verification of actual costs would not be possible, the Commission should have concluded that offers above $1,000/MWh should not set LMP, and instead, required such costs to be recovered via uplift.\35\ --------------------------------------------------------------------------- \35\ AMP/APPA Request for Rehearing at 9-13 (citing Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (Motor Vehicle Mfrs. Ass'n); United Distrib. Cos., 88 F.3d at 1169). --------------------------------------------------------------------------- 21. Exelon requests rehearing of the fact that the regulatory text does not include the ``actual or expected'' phrase when it describes the costs to be verified. Exelon argues that the current regulatory text fails to adequately capture the Commission's intent described in the preamble, specifically that costs may be either actual or expected. Exelon asserts that, in order to avoid confusion and also satisfy due process and regulatory notice requirements, the Commission should amend the regulatory text to specify that the verified costs can be ``actual or expected.'' \36\ --------------------------------------------------------------------------- \36\ Exelon Request for Clarification/Rehearing at 6-8 (citing U.S. v. Chrysler Corp., 158 F.3d 1350 (D.C. Cir. 1998); Upton v. SEC, 75 F.3d 92 (2d Cir. 1996); General Electric Co. v. EPA, 53 F.3d 1324 (D.C. Cir. 1995)). --------------------------------------------------------------------------- ii. Determination 22. We disagree with AMP/APPA's argument that the use of expected costs in the verification process to set LMPs was arbitrary and capricious, and thus deny its request for rehearing. The record demonstrates that certain natural gas resources do not know their actual short-run marginal costs at the time they submit their incremental energy offers, and thus it is just and reasonable, and consistent with current practice, for such resources to offer based on their expected costs.\37\ Given this record, the Commission appropriately responded to the many comments filed by clarifying in Order No. 831 that market participants could offer based on expected costs. In circumstances when actual costs are not known, a resource offer based on expected short-run marginal cost constitutes a competitive offer. Further, contrary to AMP/APPA's assertion, in Order No. 831 the Commission did not expand the definition of the specific types of short-run marginal costs that a resource could include in its cost-based incremental energy offer above $1,000/MWh, but rather, the Commission stated that it expected that the RTO/ISO would build on its existing mitigation processes for calculating or updating cost-based incremental energy offers. Further, in Order No. 831, the Commission required an RTO/ISO to explain in its compliance filing what factors it will consider 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. Thus, the Commission was not arbitrary and capricious because its decision to permit verified expected costs above $1,000/MWh to set LMP is consistent with current RTO/ISO practices that allow cost-based incremental energy offers to be based on expected, rather than actual costs, as demonstrated in the record.\38\ --------------------------------------------------------------------------- \37\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at PP 104- 108. \38\ See id. PP 106-107. --------------------------------------------------------------------------- 23. We grant Exelon's request to amend the regulatory text by adding the words ``actual or expected'' as suggested by Exelon. We agree that these revisions will provide more certainty to market participants and more clearly state the Commission's intention that both actual and expected costs over $1,000/MWh may be submitted for verification. b. Market Power Concerns i. Requests for Rehearing 24. AMP/APPA seek rehearing contending that Order No. 831 is arbitrary and capricious because it fails to address market power concerns that may arise if resources exaggerate expected costs included in cost-based incremental energy offers above $1,000/MWh.\39\ According to AMP/APPA, there are strong incentives for an owner of a fleet of resources, for example, to inflate expected costs of one resource during a constrained period in order to increase earnings for all of its resources. AMP/APPA further argue that there is an opportunity to inflate costs because natural gas prices are higher during constrained periods, and this is also when the price of natural gas is less transparent because the price paid by a market seller for gas on the bilateral market is farthest away from index prices.\40\ --------------------------------------------------------------------------- \39\ AMP/APPA Request for Rehearing at 13-16 (citing Motor Vehicle Mfrs. Ass'n, 463 U.S. at 43). \40\ Id. at 13-15 (citing Joint Comments of PJM and SPP, Docket No. RM16-5-000, at 10-11 (filed Apr. 4, 2016); Comments of ISO-NE Market Monitor, Docket No. RM16-5-000, at 7 (filed Apr. 4, 2016)). --------------------------------------------------------------------------- 25. AMP/APPA further assert that Order No. 831 failed to address whether [[Page 53407]] allowing offers above $1,000/MWh to set LMP could lead to market power concerns in the natural gas market.\41\ In support of this position, AMP/APPA reference the PJM Market Monitor's comments in the Order No. 831 proceeding stating that removing the offer cap entirely could exacerbate market power in the natural gas markets and also impact electricity markets.\42\ AMP/APPA further note that the Internal Market Monitor for ISO-NE (ISO-NE Market Monitor) stated that, in ISO-NE., raising the offer cap could expose the energy markets to uncompetitive conditions in the natural gas markets.\43\ AMP/APPA therefore propose that offers above $1,000/MWh should be based upon actual costs in order to be used to set LMP, since the use of expected costs can exacerbate market power concerns, but offers above $1,000/MWh based on expected costs should be recovered via uplift.\44\ --------------------------------------------------------------------------- \41\ Id. at 15-16. \42\ Id. at 15 (citing PJM Market Monitor, Comments, Docket No. RM16-5-000, at 4 (filed Apr. 4, 2016)). \43\ Id. (citing ISO-NE Market Monitor, Comments, Docket No. RM16-5-000, at 3 (filed Apr. 4, 2016)). \44\ Id. at 17. --------------------------------------------------------------------------- 26. AMP/APPA seek rehearing of Order No. 831, arguing that the Commission's use of expected costs in setting LMP was arbitrary and capricious, and that the Commission did not explain its departure from relevant precedent.\45\ Specifically, AMP/APPA argue that allowing expected costs to be used to verify cost-based incremental energy offers above $1,000/MWh contravenes the Federal Power Act (FPA) and is inconsistent with precedent requiring certain safeguards when granting market-based rates. AMP/APPA maintain that the Commission's authority under the FPA to grant market-based rate authority has been upheld in court because the Commission periodically conducts ex ante examinations of a public utility's market power as well as enforceable ex post reporting.\46\ According to AMP/APPA, however, Order No. 831 never requires RTOs/ISOs or Market Monitors to ensure that the market- clearing LMPs resulting from a seller's offer exceeding $1,000/MWh are actually cost-based. AMP/APPA assert that permitting verification based on expected costs does not meet the ex post reporting requirement that would allow the Commission to determine whether these expected costs and resulting market-clearing prices are just and reasonable. AMP/APPA therefore conclude that Order No. 831 is unlawful because the Commission cannot rely on market forces to regulate rates in lieu of imposing reporting requirements on generators.\47\ --------------------------------------------------------------------------- \45\ Id. at 8 (citing PSEG Energy Res. & Trade LLC v. FERC, 665 F.3d 203, 208 (D.C. Cir. 2011); Motor Vehicle Mfrs. Ass'n, 463 U.S. at 43; FCC v. Fox Television Stations, 556 U.S. 502, 515 (2009)). \46\ Id. at 5 (citing California ex rel. Lockyer v. FERC, 383 F.3d 1006, 1013-14 (9th Cir. 2004)). \47\ Id. at 6-8 (citing Blumenthal v. FERC, 552 F.3d 875, 882-83 (D.C. Cir. 2009); FPC v. Texaco, 417 U.S. 380, 399 (1974)). --------------------------------------------------------------------------- ii. Determination 27. We deny AMP/APPA's request for rehearing and alternative proposal regarding market power concerns and the use of expected costs. We disagree with AMP/APPA that incremental energy offers above $1,000/ MWh based on expected costs present market power concerns; the verification requirement in Order No. 831 was specifically designed to address market power concerns and ensure that all incremental energy offers above $1,000/MWh are indeed cost-based. Pursuant to the verification requirement, resources may only submit incremental energy offers above $1,000/MWh if they are cost-based, and the RTO/ISO or Market Monitoring Unit must verify that any such offer reasonably reflects that resource's actual or expected short-run marginal costs. Incremental energy offers above $1,000/MWh may not be used to calculate LMPs if such offers cannot be verified by the RTO/ISO or Market Monitoring Unit prior to the market clearing process. In Order No. 831, the Commission specifically found 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.'' \48\ The verification requirement in Order No. 831 is therefore designed to prevent the concerns AMP/APPA raise about resources including ``inflated'' or ``exaggerated'' expected costs in cost-based incremental energy offers above $1,000/MWh. --------------------------------------------------------------------------- \48\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at P 144. --------------------------------------------------------------------------- 28. We reject as unsupported AMP/APPA's claim that the Final Rule did not address concerns about market power in the natural gas market. The excerpts from the PJM Market Monitor's and ISO-NE Market Monitor's comments that AMP/APPA included in its request for rehearing expressed general concern about removing a hard cap in energy markets given potential concerns about market power in natural gas markets. However, Order No. 831 did not remove a hard cap in energy markets--it adopted a $2,000/MWh hard cap. As discussed above, we balanced several considerations in adopting a $2,000/MWh but the fact that a hard cap continues to remain in place addresses the comments AMP/APPA cites, to the extent there is market power in the natural gas markets. Additionally, the excerpt from the ISO-NE Market Monitor's comments cited by AMP/APPA discusses the relationship between natural gas markets and energy markets and expresses general concerns about limited transparency into the competitive conditions in natural gas spot markets. Again, the $2,000/MWh hard cap addresses this concern as it recognizes that the verification process required by Order No. 831 may be less effective during extreme conditions in the natural gas market.\49\ --------------------------------------------------------------------------- \49\ See id. P 87. --------------------------------------------------------------------------- 29. We deny AMP/APPA's request for rehearing regarding market-based rates because Order No. 831 does not depart from Commission precedent, and the Commission's action was not arbitrary and capricious. Contrary to AMP/APPA's claims, a market participant with market-based rate authority that submits a cost-based incremental offer above $1,000/MWh for a resource would continue to be subject to the existing reporting and other requirements that are imposed on entities with market-based rate authority,\50\ consistent with the precedent cited by AMP/APPA. Further, contrary to AMP/APPA's assertions, the verification process specifically requires that the RTO/ISO or Market Monitoring Unit ensure that incremental energy offers are in fact cost-based, meaning that the offer must reasonably reflect that resource's actual or expected short- run marginal costs.\51\ [[Page 53408]] As discussed above, the record demonstrates that it is appropriate to use expected costs in the verification of cost-based incremental energy offers because when actual costs are not known, a resource offer based on expected short-run marginal cost constitutes a competitive offer.\52\ In Order No. 831, the Commission stated that ``[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.'' \53\ Therefore, the use of expected costs in the verification process does in fact allow the Commission to determine whether the resulting market clearing prices would be just and reasonable. --------------------------------------------------------------------------- \50\ For example, entities with market-based rate authority must file Electric Quarterly Reports with the Commission, consistent with Order Nos. 2001 and 768. Revised Public Utility Filing Requirements, Order No. 2001, FERC Stats. & Regs. ] 31,127, reh'g denied, Order No. 2001-A, 100 FERC ] 61,074, reh'g denied, Order No. 2001-B, 100 FERC ] 61,342, order directing filing, Order No. 2001-C, 101 FERC ] 61,314 (2002), order directing filing, Order No. 2001-D, 102 FERC ] 61,334, order refining filing requirements, Order No. 2001-E, 105 FERC ] 61,352 (2003), order on clarification, Order No. 2001-F, 106 FERC ] 61,060 (2004), order revising filing requirements, Order No. 2001-G, 120 FERC ] 61,270, order on reh'g and clarification, Order No. 2001-H, 121 FERC ] 61,289 (2007), order revising filing requirements, Order No. 2001-I, FERC Stats. & Regs. ] 31,282 (2008); Elec. Mkt. Transparency Provisions of Section 220 of the Fed. Power Act, Order No. 768, FERC Stats. & Regs. ] 31,336 (2012), order on reh'g, Order No. 768-A, 143 FERC ] 61,054 (2013). They must also timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting their market-based rate authority. 18 CFR 35.42 (2017). \51\ See Order No. 831, FERC Stats. & Regs. ] 31,387 at P 140 (``[A]n 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.''). \52\ See supra P 22. \53\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 83. --------------------------------------------------------------------------- 2. Verification of Imports a. Request for Rehearing 30. TAPS seeks rehearing of Order No. 831's exemption of all imports from the verification requirement for incremental energy offers above $1,000/MWh and asserts that it is unjust and unreasonable and arbitrary, and that it puts internal and external resources on unequal footing.\54\ According to TAPS, the Commission's finding that some imports are not resource-specific and therefore cannot have their costs verified does not support exempting all imports from the verification requirement. Therefore, TAPS proposes that only resource-specific imports whose costs are verified by the receiving RTO/ISO should be able to set LMP, while other imports with offers above $1,000/MWh that are not verified should receive uplift payments if their costs are verified after-the-fact. TAPS further argues that failing to verify the costs of imports presents a greater opportunity and incentive for generators to exercise market power. TAPS presents a hypothetical example of a market participant that owns generators both inside and outside of an RTO/ISO and asserts that such a market participant could use its external generators to make import offers above $1,000/MWh that its internal generators would not be permitted to make. TAPS states that, if the market participant's external resource sets the LMP in the RTO/ISO (i.e., as an import), all of that market participant's internal resources would receive infra-marginal rents. According to TAPS, such behavior would be difficult to monitor because Order No. 831 does not require cost information from external resources. TAPS therefore argues that, on rehearing, the Commission should prevent import offers above $1,000/MWh from setting LMP in the importing RTO/ISO unless the import offer costs are verified in advance, and that the Commission should only permit uplift payments to imports that have been cost-verified after-the-fact.\55\ --------------------------------------------------------------------------- \54\ TAPS Request for Clarification/Rehearing at 12-15. \55\ Id. at 12-16. --------------------------------------------------------------------------- b. Determination 31. We deny TAPS' request for rehearing regarding the treatment of imports. In Order No. 831, the Commission found that exempting incremental energy offers from imports above $1,000/MWh from the verification requirement was justified because imports are not similarly situated to internal resources.\56\ Because they are not similarly situated, it was not arbitrary or capricious to treat import offers from external resources differently than offers from internal resources. Specifically, the Commission found that internal resources and imports are not similarly situated because, based on the record,\57\ it may be impossible to identify the costs underlying an import offer because they are not resource-specific. Further, Order No. 831 remains consistent with current market power mitigation measures in RTOs/ISOs that generally apply to internal resources but not to imports. --------------------------------------------------------------------------- \56\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 195. \57\ See, e.g., id. PP 180, 183, 185. --------------------------------------------------------------------------- 32. With respect to TAPS' proposed alternative which would prevent import offers above $1,000/MWh from setting LMP if the costs cannot be verified, we reject it because, as supported in the record,\58\ we continue to find that such a prohibition could discourage imports at times when they are most needed to provide additional supply and increased competition.\59\ Further, as the Commission explained in Order No. 831, such a prohibition could also result in uneconomic flows between RTOs/ISOs.\60\ --------------------------------------------------------------------------- \58\ See, e.g., id. PP 179, 181, 188-189. \59\ Id. P 193. \60\ Id. P 194. --------------------------------------------------------------------------- 33. In Order No. 831, the Commission also considered market power concerns similar to those raised by TAPS in its rehearing request, but did not find that they warranted requiring cost-verification for import offers above $1,000/MWh. The Commission explained that because ``market participants can import energy from adjacent markets and sell that energy in the RTO/ISO energy market . . . it is difficult for external resources in an adjacent market to withhold.'' \61\ The hypothetical example TAPS presents in its request for rehearing does not persuade us otherwise. First, and as the Commission explained in Order No. 831, it is unlikely that a resource-specific import transaction can successfully withhold energy from the destination market because any resource-specific import transaction is also competing against an import transaction that simply buys from the export market at the prevailing export market price. Second, the import offer in that example would only benefit a market participant that owns a fleet of internal and external generation (which is online and being compensated at the LMP in TAPS' hypothetical example) if the import offer actually cleared the importing RTO/ISO's energy market. However, such an import offer would only clear this market at a price above $1,000/MWh if it were below the verified cost-based incremental energy offers of other internal resources and below other import offers. Thus, such an import would be beneficial to the importing RTO/ISO market as it would lower the clearing price compared to a situation without it. Therefore, TAPS' example demonstrates that imports can lower an importing RTO/ISO's LMP, which supports the Commission's rationale for allowing import offers above $1,000/MWh to set LMP.\62\ For these additional reasons, we find that the regulations regarding the treatment of imports in Order No. 831 are just and reasonable and not arbitrary and capricious and reject TAPS' proposal to prevent import offers above $1,000/MWh from setting LMP in the importing RTO/ISO unless the import offer's costs have been verified. For similar reasons, we deny TAPS' proposal regarding uplift payments to imports. Finally, we note that in Order No. 831, the Commission stated it would consider RTO/ISO proposals under FPA section 205 to verify or otherwise review the costs of imports or exports and/ or develop additional mitigation provisions for import and export transactions with offers above $1,000/MWh.\63\ --------------------------------------------------------------------------- \61\ Id. P 196. \62\ Order No. 831 does not apply to emergency purchases, such as emergency import purchases. See id. P 198. \63\ Id. P 197. --------------------------------------------------------------------------- [[Page 53409]] C. Costs Included in Cost-Based Incremental Energy Offers 1. Requests for Rehearing/Clarification 34. Exelon requests clarification, and alternatively rehearing, that the Commission did not intend to exclude any particular categories of variable costs, particularly those not tied to the price of the commodity associated with the resource's fuel supply. Exelon asserts that a resource's cost-based incremental energy offer is comprised not only of those costs linked to the price of fuel, but also of other variable costs, including but not limited to balancing costs and transportation costs. Exelon states that if the Commission does not grant its requested clarification, then it seeks rehearing on the basis that exclusion of other variable costs from cost-based incremental energy offers would lead to an unjust and unreasonable result.\64\ --------------------------------------------------------------------------- \64\ Exelon Request for Clarification/Rehearing at 4-6, 7-8 (citing Motor Vehicle Mfrs. Ass'n, 463 U.S. at 43; NorAm Gas Transmission Co. v. FERC, 148 F.3d 1158, 1165 (D.C. Cir. 1998); PPL Wallingford Energy LLC v. FERC, 419 F.3d 1194, 1198 (D.C. Cir. 2005)). --------------------------------------------------------------------------- 35. TAPS requests clarification, and alternatively rehearing, regarding whether opportunity costs may be recovered in addition to the $100/MWh adder.\65\ TAPS asserts that in Order No. 831, the Commission did not respond to the arguments it raised in response to the NOPR, did not explicitly state whether the $100/MWh adder includes opportunity costs, and did not state whether RTOs/ISOs can allow opportunity costs when developing their verification methodologies. TAPS asks the Commission to clarify that if an RTO/ISO allows adders, the maximum total amount of such adders, including both opportunity costs and any other difficult-to-quantify costs, cannot exceed $100/MWh. TAPS asserts that, if the Commission intended to permit RTOs/ISOs to propose verification methodologies that allow for the recovery of opportunity costs in addition to the $100/MWh adder, the Commission should grant rehearing because opportunity costs should not be allowed under the ``extreme'' price levels at issue in this proceeding.\66\ --------------------------------------------------------------------------- \65\ TAPS Request for Clarification/Rehearing at 2 (citing Canadian Ass'n of Petroleum Producers, 254 F.3d 289). \66\ Id. at 16-18 (citing PJM Interconnection, L.L.C., 126 FERC ] 61,145, at P 28 n.34 (2009) (``The opportunity cost associated with providing `must run' output is the value associated with the lost opportunity to produce energy during a higher valued time period within the year.'')). --------------------------------------------------------------------------- 36. NYISO requests that the Commission clarify that, when calculating uplift payments for the recovery of verified costs, only actual, documented out-of-pocket costs should be paid after-the-fact and that no risk-related adders or opportunity costs be allowed when cost information is not submitted in a sufficiently timely manner to permit review and verification. NYISO states that it is concerned that the submission of legitimate, verifiable costs that exceed the $1,000/ MWh offer cap close in time to the day-ahead or real-time market close could deny NYISO sufficient time to perform cost verification. NYISO states that this could cause the resource's offer to be mitigated to a level that does not include the unverified, additional costs and could cause the resource to be committed when it would not have otherwise been or receive a larger schedule than it otherwise would have. NYISO asserts that its requested clarification would ensure all resources have an incentive to submit timely information to the RTO/ISO.\67\ --------------------------------------------------------------------------- \67\ NYISO Request for Clarification/Rehearing at 15-16. --------------------------------------------------------------------------- 2. Determination 37. We deny Exelon's request for clarification, and alternatively rehearing, regarding whether the verification requirement intended to exclude particular categories of actual or expected costs, particularly variable costs that are non-fuel related costs. In Order No. 831, the Commission neither required RTOs/ISOs to change the methodologies they currently use to develop cost-based offers in order to satisfy the verification requirement nor prescribed the specific types of short-run marginal costs that could be included in cost-based incremental energy offers above $1,000/MWh. We do not prejudge what types of costs RTOs/ ISOs may propose as part of their compliance filings. 38. We deny TAPS' request for clarification, and alternatively rehearing, regarding whether the $100/MWh limit on adders applies to opportunity costs. Opportunity costs are legitimate short-run marginal costs and not adders above cost. Cost-based incremental energy offers based on opportunity costs may currently set LMP in many RTOs/ISOs. Given that, in Order No. 831, the Commission did not require RTOs/ISOs to change the specific costs that they permit resources to include in cost-based incremental energy offers, resources in RTOs/ISOs that permit the use of opportunity costs in this manner may continue to do so after implementing Order No. 831. Because opportunity costs should be considered part of a cost-based incremental energy offer, whether or not the offer exceeds $1,000/MWh, verifiable opportunity costs should not be subject to the $100/MWh limit on adders above cost. We do not prejudge the validity of including verifiable opportunity costs in cost-based incremental offers above $1,000/MWh or the verification methods of such costs that RTOs/ISOs may propose as part of their compliance filings. We also reject TAPS' argument that the Commission failed to meaningfully address its arguments stating that opportunity costs should not be permitted at the ``extreme'' prices contemplated in this rulemaking.\68\ As stated above, in a rulemaking, the Commission need not respond to every comment or analyze every alternative.\69\ As explained here, opportunity costs are legitimate short-run marginal costs that should be considered part of a cost-based incremental energy offer, regardless of whether that offer exceeds $1,000/MWh. Some current RTO/ISO practices permit cost-based incremental energy offers based on opportunity costs to set LMP, and the Commission in Order No. 831 did not require RTOs/ISOs to change which costs they may include in cost-based incremental energy offers. Therefore, TAPS' comments would not have resulted in a change in the rule. --------------------------------------------------------------------------- \68\ TAPS Request for Clarification/Rehearing at 17-18. \69\ See supra P 12 (citing American Min. Congress, 907 F.2d at 1187-88; (citing Thompson, 741 F.2d at 408; ACLU, 823 F.2d at 1581)). --------------------------------------------------------------------------- 39. We grant NYISO's request for clarification regarding the calculation of uplift payments. Resources are only eligible to receive uplift payments to make them whole to, at most, their submitted cost- based incremental energy offers if the associated offer and cost information is submitted in a sufficiently timely manner and verified by the RTO/ISO, meaning offers and supporting information must be provided consistent with RTO/ISO offer submission guidelines and approved by the RTO/ISO or Market Monitoring Unit. Consistent with Order No. 831, the after-the-fact uplift payment that a resource would be eligible to receive if its cost-based incremental energy offer above $1,000/MWh is not verified prior to market clearing shall include only actual verifiable costs. We agree with NYISO that opportunity costs, like other costs, must be submitted in a timely manner. However, we clarify that if a resource avails itself of an RTO's/ISO's current rules to allow a resource to include opportunity costs in its cost- based incremental energy offer, then that RTO/ISO must give that resource an [[Page 53410]] opportunity to recover those opportunity costs through an uplift payment, subject to verification. We further clarify that a resource may not receive uplift payments for incremental energy costs in excess of the costs included in its verified incremental energy offer. That is, a resource may not submit a cost-based incremental energy offer based on expected costs prior to the market clearing process and subsequently receive uplift payments to make it whole to an offer above the $/MWh level(s) of its offer(s).\70\ In this instance, allowing a resource to receive uplift in excess of its verified cost-based incremental energy offer could give that resource the incentive to submit offers that do not reflect its actual short-run marginal costs and could thus result in inefficient resource selection. --------------------------------------------------------------------------- \70\ For example, a resource may not submit a $2,300/MWh offer based on expected short-run marginal cost that is verified and clears the market and receive uplift associated with incremental energy costs above $2,300/MWh, even if that resource's actual short- run marginal cost, based on an after-the-fact review, is $2,500/MWh. --------------------------------------------------------------------------- 40. Further, such after-the-fact uplift payments may not include any adders above cost, including risk related adders, because actual costs are known after-the-fact.\71\ This finding is consistent with Commission precedent regarding PJM's requests for waivers of certain tariff provisions related to its offer cap.\72\ --------------------------------------------------------------------------- \71\ Order No. 831, FERC Stats. & Regs. ] 31,387 at P 146. \72\ In the 2015 PJM offer cap order, the Commission found that ``the 10 percent adder [above costs] is unjust and unreasonable as applied to ex post review of documented costs, because the cost [sic] are no longer uncertain.'' See PJM Interconnection L.L.C., 153 FERC ] 61,289, at P 31 (2015). See also PJM Interconnection, L.L.C., 149 FERC ] 61,059, at P 13 (2014). --------------------------------------------------------------------------- III. Information Collection Statement 41. The Paperwork Reduction Act (PRA) \73\ 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,\74\ in turn, require approval of certain information collection requirements imposed by agency rules. --------------------------------------------------------------------------- \73\ 44 U.S.C. 3501-3520. \74\ 5 CFR 1320 (2017). --------------------------------------------------------------------------- 42. The Commission is amending its regulations to clarify what the Commission already required in Order No. 831--that either actual or expected costs included in incremental energy offers above $1,000/MWh may be submitted for verification. The Commission estimates that there will be no net change to burden. 43. Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: [email protected], phone: (202) 502-8663, fax: (202) 273-0873]. Comments concerning the requirements of this rule may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security reasons, comments should be sent by email to OMB at [email protected]. Comments submitted to OMB should refer to FERC-516C and OMB Control Number 1902-0287. IV. Regulatory Flexibility Act Certification 44. The Regulatory Flexibility Act of 1980 (RFA) \75\ 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. The Commission has determined that there will not be a significant impact on a substantial number of small entities, therefore these requirements under the RFA do not apply. --------------------------------------------------------------------------- \75\ 5 U.S.C. 601-12. --------------------------------------------------------------------------- V. Document Availability 45. 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 FERC's Home Page (http://www.ferc.gov) and in FERC'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. 46. From FERC'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 excluding the last three digits of this document in the docket number field. 47. User assistance is available for eLibrary and the FERC's Web site during normal business hours from FERC Online Support at 202-502- 6652 (toll free at 1-866-208-3676) or email at [email protected], or the Public Reference Room at (202) 502- 8371, TTY (202)502-8659. Email the Public Reference Room at [email protected]. VI. Effective Date 48. These regulations are effective January 16, 2018. List of Subjects in 18 CFR Part 35 Electric power rates, Electric utilities, Non-discriminatory open access transmission tariffs. By the Commission. Issued: November 9, 2017. Nathaniel J. Davis, Sr., Deputy Secretary. Regulatory Text 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. Revise Sec. 35.28(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 actual or expected 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 actual or expected 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 [[Page 53411]] resource's actual 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. [FR Doc. 2017-24803 Filed 11-15-17; 8:45 am] BILLING CODE 6717-01-P
![Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 53403
maximum continuous thrust, and Issued in Burlington, Massachusetts, on determinations in Order No. 831, which
deceleration to ground idle. November 8, 2017. amended its regulations to address
Robert J. Ganley, incremental energy offer caps in markets
(2) The throttle movement from
ground idle to rated takeoff or maximum Manager, Engine and Propeller Standards operated by regional transmission
Branch, Aircraft Certification Service. organizations and independent system
continuous thrust and from rated takeoff
thrust to ground idle should be not more [FR Doc. 2017–24812 Filed 11–15–17; 8:45 am] operators.
BILLING CODE 4910–13–P DATES: This rule is effective January 16,
than one (1) second, except that, if
different regimes of control operations 2018.
are incorporated necessitating FOR FURTHER INFORMATION CONTACT:
scheduling of the thrust-control lever DEPARTMENT OF ENERGY Emma Nicholson (Technical
motion in going from one extreme Information), Office of Energy Policy
Federal Energy Regulatory and Innovation, Federal Energy
position to the other, a longer period of
Commission Regulatory Commission, 888 First
time is acceptable, but not more than
two (2) seconds. The throttle movement Street NE., Washington, DC 20426,
18 CFR Part 35 (202) 502–8846, emma.nicholson@
from rated maximum continuous thrust
to ground idle should not be more than [Docket No. RM16–5–001; Order No. 831– ferc.gov
five (5) seconds. A] Pamela Quinlan (Technical
Information), Office of Energy Market
(3) The time durations for each cycle Offer Caps in Markets Operated by Regulation, Federal Energy Regulatory
associated with either takeoff or Regional Transmission Organizations Commission, 888 First Street NE.,
maximum continuous thrust segments and Independent System Operators Washington, DC 20426, (202) 502–
must include all maximums allowed in 6179, pamela.quinlan@ferc.gov
the TCDS and expected service AGENCY: Federal Energy Regulatory
Anne Marie Hirschberger (Legal
operation, and must include the Commission, Department of Energy.
Information), Office of the General
following cycles: ACTION: Order on rehearing and Counsel, Federal Energy Regulatory
(i) Three (3) cycles of 5 minutes each clarification. Commission, 888 First Street NE.,
and one (1) cycle of 10 minutes at the SUMMARY: The Federal Energy Washington, DC 20426, (202) 502–
takeoff thrust. Regulatory Commission is granting in 8387, annemarie.hirschberger@
(ii) Three (3) cycles of 30 minutes part and denying in part requests for ferc.gov
each at the maximum continuous thrust. rehearing and clarification of its SUPPLEMENTARY INFORMATION:
TABLE OF CONTENTS
Paragraph Nos.
I. Introduction ............................................................................................................................................................................... 1
II. Discussion ................................................................................................................................................................................ 5
A. Offer Cap Structure .......................................................................................................................................................... 5
1. Hard Cap Level .......................................................................................................................................................... 6
2. Implementation of the Hard Cap .............................................................................................................................. 13
B. Verification Requirement ................................................................................................................................................. 18
1. Expected Costs ........................................................................................................................................................... 19
2. Verification of Imports .............................................................................................................................................. 30
C. Costs Included in Cost-Based Incremental Energy Offers .............................................................................................. 34
1. Requests for Rehearing/Clarification ........................................................................................................................ 34
2. Determination ............................................................................................................................................................. 37
III. Information Collection Statement .......................................................................................................................................... 41
IV. Regulatory Flexibility Act Certification ................................................................................................................................ 44
V. Document Availability ............................................................................................................................................................ 45
VI. Effective Date .......................................................................................................................................................................... 48
I. Introduction prices (LMPs). California Independent and independent system operator (RTO/
1. On November 17, 2016, the Federal System Operator Corporation (CAISO), ISO): (1) Cap each resource’s
Energy Regulatory Commission ISO New England Inc. (ISO–NE), incremental energy offer at the higher of
(Commission) issued Order No. 831.1 Midcontinent Independent System $1,000/MWh or that resource’s verified
Order No. 831 addresses the Operator, Inc. (MISO), New York cost-based incremental energy offer; and
Independent System Operator, Inc. (2) cap verified cost-based incremental
incremental energy offer component of
(NYISO), and Southwest Power Pool, energy offers at $2,000/MWh when
a resource’s supply offer, which is a
Inc. (SPP) currently have a $1,000/MWh calculating LMPs (hard cap).3 Resources
financial component consisting of costs
cap on incremental energy offers (offer with verified cost-based incremental
that vary with a resource’s output or
cap), and PJM Interconnection, L.L.C.
level of demand reduction. Incremental energy offers above $2,000/MWh will be
(PJM) currently has an offer cap of
nshattuck on DSK9F9SC42PROD with RULES
energy offers are one of the components eligible to receive uplift.4 In response to
$2,000/MWh on cost-based offers.2
used to calculate locational marginal 2. In Order No. 831, the Commission comments on the Notice of Proposed
1 Offer Caps in Markets Operated by Regional
amended its regulations to require that
Transmission Organizations and Independent each regional transmission organization
System Operators, 81 FR 87,770 (Dec. 5, 2016),
3 Id. P 1.
FERC Stats. & Regs. ¶ 31,387 (2016) (Order No. 2 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
831). PP 11–13. 4 Id. P 78.
VerDate Sep<11>2014 14:33 Nov 15, 2017 Jkt 244001 PO 00000 Frm 00007 Fmt 4700 Sfmt 4700 E:\FR\FM\16NOR1.SGM 16NOR1](https://thefederalregister.org/doc/82_FR_53623/page/1.svg)
![53404 Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations
Rulemaking,5 the Commission clarified For the reasons discussed below, we Commission determined that a hard cap
that each RTO/ISO or Market grant in part and deny in part the was necessary to limit any adverse
Monitoring Unit must verify that any requests for rehearing and clarification. impact on LMPs due to imperfect
incremental energy offer above $1,000/ information about a resource’s short-run
II. Discussion
MWh reasonably reflects the associated marginal costs that might arise during
resource’s actual or expected costs, as A. Offer Cap Structure the verification process.14 The
opposed to only the resource’s actual 5. The requests for rehearing and Commission also recognized that a hard
costs, prior to using that offer to clarification regarding the offer cap cap that is too low might suppress LMPs
calculate LMP.6 structure focus on the level of the hard below the marginal cost of production.15
3. With respect to treatment of cost- cap and the implementation of the hard In determining the $2,000/MWh level of
based incremental energy offers above cap. the hard cap, the Commission therefore
$2,000/MWh, the Commission stated struck a balance between competing
that it expects RTOs/ISOs to use such 1. Hard Cap Level goals: (1) Limiting any adverse impacts
offers to determine merit-order dispatch, a. Request for Rehearing on LMPs due to imperfect information
and it cited PJM as an example of an during the verification process and (2)
RTO/ISO that uses cost-based 6. TAPS seeks rehearing and argues
both that the $2,000/MWh hard cap reducing the likelihood of suppressing
incremental energy offers above $2,000/ LMPs below the marginal cost of
MWh to determine merit-order dispatch, level established by the Commission is
not supported by substantial evidence, production.
but limits cost-based incremental energy 8. The overall offer cap structure set
offers to $2,000/MWh for purposes of and that the $1,724/MWh offer cited in
forth in Order No. 831 and the overall
calculating LMP.7 The Commission Order No. 831 was not a legitimate cost-
market structure of RTOs/ISOs in which
found that imports should be permitted based incremental energy offer.11
the offers arise affected the balance
to offer above $1,000/MWh, but will not Rather, TAPS states, the $1,724/MWh
offer was the estimated cost of a struck by the Commission in setting the
be subject to verification.8 Finally, level of the hard cap. The hard cap does
while Order No. 831 did not require resource calculated according to PJM’s
Cost Development Guidelines, but the not stand alone, meaning that it is not
RTOs/ISOs to include an adder above the only way of ensuring that an offer
cost in cost-based incremental energy actual cost of that resource was less than
$1,500/MWh. TAPS argues that, given does not reflect the exercise of market
offers above $1,000/MWh, the power and that the price resulting from
Commission stated that if an RTO/ISO the large discrepancy between estimated
and actual costs, it was inappropriate an incremental energy offer is just and
chooses to retain existing rules that reasonable. In balancing the competing
allow for an adder above cost or for the Commission to rely on an
estimated $1,724/MWh offer as the basis goals, the Commission effectively
proposes any new adders above cost, recognized that the hard cap serves as
such adders may not exceed $100/ for the $2,000/MWh hard cap level.
TAPS asserts that, even if it was a backstop to the mitigation established
MWh.9 However, in Order No. 831, the through both the cost-based requirement
appropriate for the Commission to rely
Commission did not require RTOs/ISOs and the verification process—the other
upon estimated costs, the Commission
to change the costs they currently elements of the offer cap structure. The
should not have used the $1,724/MWh
include in cost-based incremental cost-based offer requirement serves a
level, since it was estimated using a
energy offers, and it did not address ‘‘mitigation function’’ 16 by requiring
methodology that is not compliant with
whether verifiable opportunity costs are incremental energy offers above $1,000/
Order No. 831. TAPS contends that the
subject to the $100/MWh limit on MWh be cost-based. The verification
Commission should instead set the hard
adders. requirement also addresses market
cap level at $1,500/MWh or,
4. On December 19, 2016, the power concerns.17 The hard cap
alternatively, at $1,800/MWh if the
Commission received four requests for ‘‘limit[s] the adverse impact that any
Commission determines that there was
rehearing and/or clarification of Order imperfect information about resources’
a legitimate cost-based incremental
No. 831 which raise issues related to the short-run marginal costs during the
energy offer of $1,724/MWh.12 TAPS
structure of the offer cap, the verification process could have on
also argues that the Commission failed
verification requirement, and the costs LMPs.’’ 18 The Commission factored in
to meaningfully address the analytical
included in cost-based incremental these two other elements of the offer-cap
evidence TAPS presented in its
energy offers. TAPS filed a request for structure in balancing the competing
comments supporting a $1,500/MWh
rehearing and clarification. NYISO filed goals to set the level of the hard cap.
hard cap.13
a request for clarification and, 9. In setting that level, the
alternatively, request for rehearing. b. Determination Commission also considered the overall
AMP/APPA filed a request for 7. We deny TAPS’ request for market structure of RTOs/ISOs—a
rehearing. Exelon filed a motion for rehearing of the $2,000/MWh level of structure designed to ensure that
clarification and request for rehearing.10 the hard cap. In Order No. 831, the markets are competitive and not subject
to the exercise of market power, through
5 Offer Caps in Markets Operated by Regional
of Practice and Procedure prohibits answers to for instance, existing market power
Transmission Organizations and Independent requests for rehearing. 18 CFR 385.713(d)(2) (2017).
System Operators, 81 FR 5951 (Feb. 4, 2016), FERC mitigation processes.19 The hard cap
We therefore reject the answer of the PJM Market
Stats. & Regs. ¶ 32,714, at PP 3 (2016) (NOPR). Monitor. We will treat MISO’s comments as an
6 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at 14 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
answer and as a result reject them.
P 139. 11 TAPS Request for Clarification/Rehearing at 2 P 87.
7 Id. P 90. 15 Id. P 91.
(citing Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315
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8 Id. P 192. 16 Id. P 83.
(D.C. Cir. 2004); Canadian Ass’n of Petroleum
9 Id. P 207. Producers v. FERC, 254 F.3d 289 (D.C. Cir. 2001) 17 Id. P 139.
10 The Independent Market Monitor for PJM (PJM (Canadian Ass’n of Petroleum Producers)). 18 Id. P 87.
12 Id. at 5–11.
Market Monitor) filed an answer to Exelon’s motion 19 Cf. id. PP 85–90. Additionally, all six RTOs/
for clarification and request for rehearing. MISO 13 Id. at 10 (citing Canadian Ass’n of Petroleum ISOs have market power mitigation rules designed
filed comments in support of NYISO’s request for Producers, 254 F.3d at 299 (an agency’s ‘‘failure to to prevent market participants from exercising
clarification and, alternatively, request for respond meaningfully’’ to objections raised by a market power. See, e.g., California Independent
rehearing. Rule 713(d)(1) of the Commission’s Rules party renders its decision arbitrary and capricious)). System Operator Corporation, eTariff, 39; ISO New
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![Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 53405
also serves as backstop to those existing alternative proposal. The Commission LMPs that is separate from the process
market mitigation processes.20 addressed this alternative in adopting for determining resource schedules.
10. Based on the record, the the $2,000/MWh hard cap.23 In any However, NYISO states that it uses a
Commission set the level of the hard cap event, in a rulemaking, the Commission common ex ante process to determine
to $2,000/MWh. The Commission need not respond to every comment or both locational based marginal prices
determined that $2,000/MWh was the analyze every alternative. Rather, the (LBMPs) and resource schedules.
level that short-run marginal costs Commission must respond to NYISO asserts that, because its process
would rarely exceed.21 The cost-based ‘‘comments which, if true. . .would utilizes the same offers for scheduling
incremental energy offer of $1,724/MWh require a change in an agency’s and pricing, it would be challenging to
referenced in Order No. 831, and which proposed rule.’’ 24 The Commission’s allow resources to be committed and
TAPS questions, regardless of the determination regarding the $2,000/ scheduled based on validated
methodology by which it was derived, MWh hard cap is not invalidated merely incremental energy offers above $2,000/
was only one point of reference for the because there may be a reasonable MWh, but then cap the offers for
Commission within the context of the alternative.25 purposes of calculating LBMPs and
broader record. Specifically, the ancillary services prices. According to
Commission also examined the 2. Implementation of the Hard Cap
NYISO, this would require resource-
evidence in the record regarding high a. Requests for Rehearing/Clarification intensive and potentially costly software
natural gas prices that occurred during 13. NYISO seeks clarification that changes, make validation of prices and
the Polar Vortex when some resources Order No. 831 does not require that schedules more complex, and require
experienced short-run marginal costs incremental energy offers above $2,000/ NYISO to redirect resources from other
above $1,000/MWh.22 MWh be used to determine merit-order efforts that are more certain to benefit
11. The alternative $1,500/MWh and dispatch in all RTOs/ISOs, and, in the consumers and markets. Additionally,
$1,800/MWh hard cap levels that TAPS alternative, seeks rehearing on this NYISO contends that implementing an
proposed would result in a balance issue.26 NYISO states that, to the extent offer cap that only limits the offer prices
different than the one chosen by the the Commission intended to establish a used to determine LBMPs can lead to a
Commission. Lower hard cap levels requirement, the Commission did not divergence between resource schedules
such as these would increase the seek comment on the requirement in the and prices that can harm market
likelihood of suppressing prices below NOPR, did not demonstrate that the participants.29
the marginal cost of production and requirement must be imposed on all 15. In addition, NYISO requests
would thereby run contrary to the RTOs/ISOs in order to ensure just and clarification that RTOs/ISOs are
Commission’s price formation efforts to reasonable rates, and did not consider permitted to apply the same offer cap to
ensure that LMPs reflect the short-run the burdens the requirement would
marginal cost of the marginal resource. both incremental energy and minimum
impose on NYISO.27 generation offers,30 and in the
We therefore reject TAPS’ request for 14. NYISO asserts that such a
rehearing and the alternative hard cap alternative seeks rehearing on this issue.
requirement would introduce foreign Currently, NYISO’s tariff applies a
levels proposed. As stated above, we market design elements into NYISO that
continue to find that the $2,000/MWh $1,000/MWh offer cap to all day-ahead
were developed by PJM to be and real-time energy offers, including
hard cap reasonably balances reducing compatible with its own pricing
the likelihood of suppressing LMPs minimum generation offers. NYISO
method, market rules, and software.28 argues that applying different offer caps
while limiting any adverse impact on Specifically, NYISO explains that PJM’s
LMPs from imperfect information about to incremental energy offers and
design accommodates discrepancies minimum generation offers could
resources’ short-run marginal costs between schedules and price, using a
during the verification process. incentivize suppliers to artificially
secondary ex post process to determine shape their offers to conform to the
12. Further, we reject TAPS’ argument
that the Commission failed to 23 Id.
different offer caps rather than offer in
meaningfully address its $1,500/MWh 24 American Min. Congress v. EPA, 907 F.2d 1179,
a manner that accurately reflects a
1187–88 (D.C. Cir. 1990) (American Min. Congress) resource’s costs, which would result in
England Inc., Markets and Services Tariff, Market (citing Thompson v. Clark, 741 F.2d 401, 408 (D.C. less optimal commitment, dispatch, and
Rule 1, Appendix A; Midcontinent Independent Cir. 1984) (Thompson); ACLU v. FCC, 823 F.2d pricing. Furthermore, NYISO states that
System Operator, Inc., FERC Electric Tariff, Module 1554, 1581 (D.C. Cir.1987) (ACLU)).
25 See United Distribution Cos. v. FERC, 88 F.3d
if minimum generation offer caps are
D; New York Independent System Operator, Inc.,
Market Administration and Control Area Services 1105, 1169–70 (D.C. Cir. 1996) (United Distribution lower than incremental energy offer
Tariff, Attachment H; PJM Interconnection, L.L.C., Cos.) (‘‘FERC correctly counters that the fact that caps, generators may not offer to supply
Intra-PJM Tariffs, OATT, Tariff Operating AEPCO may have proposed a reasonable alternative energy if they do not expect to be able
Agreement, Attachment M; and Southwest Power . . . is not compelling. The existence of a second to recoup their costs.31 NYISO also
Pool, Inc., OATT, Sixth Revised Volume No. 1, reasonable course of action does not invalidate an
Attachment AF. agency’s determination.’’). states that the Commission previously
20 Cf. id. P 89. 26 See Order No. 831, FERC Stats. & Regs. ¶ granted waiver of the $1,000/MWh offer
21 See id. n.200 (citing Envtl. Action, Inc. v. FERC, 31,387 at P 90 (‘‘With respect to the treatment of cap on both incremental energy offers
939 F.2d 1057, 1064 (D.C. Cir. 1991) (‘‘it is within cost-based incremental energy offers above $2,000/ and minimum generation offers in
the scope of the agency’s expertise to make such a MWh, we expect RTOs/ISOs to use such offers to
prediction about the market it regulates, and a determine merit-order dispatch. We note that the
Commission allowed this approach when accepting 29 Id.at 7–11.
reasonable prediction deserves our deference
notwithstanding that there might also be another PJM’s current offer cap structure. . . .’’ ’’). 30 InNYISO, the first block in a resource’s
reasonable view.’’). See also Michigan Consol. Gas 27 NYISO Request for Clarification/Rehearing at 5, incremental energy offer is called a ‘‘minimum
Co. v. FERC, 883 F.2d 117, 124 (1989) (‘‘It is also 11–13. generation bid’’ and includes the costs a resource
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quite clear FERC may make predictions—‘‘[m]aking 28 NYISO also maintains that RTOs/ISOs do not incurs to operate at its economic minimum
. . . predictions is clearly within the Commission’s need to have identical software or market rules, and operating level. NYISO, Manual 11—Day-Ahead
expertise’’ and will be upheld if ‘‘rationally based that the practical ability to implement software Scheduling Manual, Sec. 4.3.3. (October 2016)
on record evidence.’’) (citing East Tennessee changes justifies accommodating regional http://www.nyiso.com/public/webdocs/markets_
Natural Gas Co. v. FERC, 863 F.2d 932, 938–39 circumstances. Id. at 6 (citing N.Y. Indep. Sys. operations/documents/Manuals_and_Guides/
(1988) (citing Associated Gas Distributors v. FERC, Operator, Inc., 142 FERC ¶ 61,202, at PP 24–26 Manuals/Operations/dayahd_schd_mnl.pdf.
824 F.2d 981, 1008 (1987)))). (2013); N.Y. Indep. Sys. Operator, Inc., 133 FERC 31 NYISO Request for Clarification/Rehearing at
22 Id. P 92. ¶ 61,246, at P 25 (2010)). 13–15.
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![Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 53407
allowing offers above $1,000/MWh to clearing prices are just and reasonable. hard cap. As discussed above, we
set LMP could lead to market power AMP/APPA therefore conclude that balanced several considerations in
concerns in the natural gas market.41 In Order No. 831 is unlawful because the adopting a $2,000/MWh but the fact that
support of this position, AMP/APPA Commission cannot rely on market a hard cap continues to remain in place
reference the PJM Market Monitor’s forces to regulate rates in lieu of addresses the comments AMP/APPA
comments in the Order No. 831 imposing reporting requirements on cites, to the extent there is market power
proceeding stating that removing the generators.47 in the natural gas markets. Additionally,
offer cap entirely could exacerbate the excerpt from the ISO–NE Market
ii. Determination
market power in the natural gas markets Monitor’s comments cited by AMP/
and also impact electricity markets.42 27. We deny AMP/APPA’s request for APPA discusses the relationship
AMP/APPA further note that the rehearing and alternative proposal between natural gas markets and energy
Internal Market Monitor for ISO–NE regarding market power concerns and markets and expresses general concerns
(ISO–NE Market Monitor) stated that, in the use of expected costs. We disagree about limited transparency into the
ISO–NE., raising the offer cap could with AMP/APPA that incremental competitive conditions in natural gas
expose the energy markets to energy offers above $1,000/MWh based spot markets. Again, the $2,000/MWh
uncompetitive conditions in the natural on expected costs present market power hard cap addresses this concern as it
gas markets.43 AMP/APPA therefore concerns; the verification requirement recognizes that the verification process
propose that offers above $1,000/MWh in Order No. 831 was specifically required by Order No. 831 may be less
should be based upon actual costs in designed to address market power effective during extreme conditions in
order to be used to set LMP, since the concerns and ensure that all the natural gas market.49
use of expected costs can exacerbate incremental energy offers above $1,000/ 29. We deny AMP/APPA’s request for
market power concerns, but offers above MWh are indeed cost-based. Pursuant to rehearing regarding market-based rates
$1,000/MWh based on expected costs the verification requirement, resources because Order No. 831 does not depart
should be recovered via uplift.44 may only submit incremental energy from Commission precedent, and the
26. AMP/APPA seek rehearing of offers above $1,000/MWh if they are Commission’s action was not arbitrary
Order No. 831, arguing that the cost-based, and the RTO/ISO or Market and capricious. Contrary to AMP/
Commission’s use of expected costs in Monitoring Unit must verify that any APPA’s claims, a market participant
setting LMP was arbitrary and such offer reasonably reflects that with market-based rate authority that
capricious, and that the Commission did resource’s actual or expected short-run submits a cost-based incremental offer
not explain its departure from relevant marginal costs. Incremental energy above $1,000/MWh for a resource would
precedent.45 Specifically, AMP/APPA offers above $1,000/MWh may not be continue to be subject to the existing
argue that allowing expected costs to be used to calculate LMPs if such offers reporting and other requirements that
used to verify cost-based incremental cannot be verified by the RTO/ISO or are imposed on entities with market-
energy offers above $1,000/MWh Market Monitoring Unit prior to the based rate authority,50 consistent with
contravenes the Federal Power Act market clearing process. In Order No. the precedent cited by AMP/APPA.
(FPA) and is inconsistent with 831, the Commission specifically found Further, contrary to AMP/APPA’s
precedent requiring certain safeguards that ‘‘the verification requirement assertions, the verification process
when granting market-based rates. reasonably addresses market power specifically requires that the RTO/ISO
AMP/APPA maintain that the concerns associated with incremental or Market Monitoring Unit ensure that
Commission’s authority under the FPA energy offers above $1,000/MWh
incremental energy offers are in fact
to grant market-based rate authority has because such offers will be required to
cost-based, meaning that the offer must
been upheld in court because the be cost-based, which should deter
reasonably reflect that resource’s actual
Commission periodically conducts ex attempts by resources to exercise market
or expected short-run marginal costs.51
ante examinations of a public utility’s power.’’ 48 The verification requirement
market power as well as enforceable ex in Order No. 831 is therefore designed 49 See id. P 87.
post reporting.46 According to AMP/ to prevent the concerns AMP/APPA 50 For example, entities with market-based rate
APPA, however, Order No. 831 never raise about resources including authority must file Electric Quarterly Reports with
requires RTOs/ISOs or Market Monitors ‘‘inflated’’ or ‘‘exaggerated’’ expected the Commission, consistent with Order Nos. 2001
costs in cost-based incremental energy and 768. Revised Public Utility Filing Requirements,
to ensure that the market-clearing LMPs Order No. 2001, FERC Stats. & Regs. ¶ 31,127, reh’g
resulting from a seller’s offer exceeding offers above $1,000/MWh. denied, Order No. 2001–A, 100 FERC ¶ 61,074,
$1,000/MWh are actually cost-based. 28. We reject as unsupported AMP/ reh’g denied, Order No. 2001–B, 100 FERC ¶ 61,342,
AMP/APPA assert that permitting APPA’s claim that the Final Rule did order directing filing, Order No. 2001–C, 101 FERC
verification based on expected costs not address concerns about market ¶ 61,314 (2002), order directing filing, Order No.
power in the natural gas market. The 2001–D, 102 FERC ¶ 61,334, order refining filing
does not meet the ex post reporting requirements, Order No. 2001–E, 105 FERC ¶ 61,352
requirement that would allow the excerpts from the PJM Market Monitor’s (2003), order on clarification, Order No. 2001–F,
Commission to determine whether these and ISO–NE Market Monitor’s 106 FERC ¶ 61,060 (2004), order revising filing
expected costs and resulting market- comments that AMP/APPA included in requirements, Order No. 2001–G, 120 FERC
its request for rehearing expressed ¶ 61,270, order on reh’g and clarification, Order No.
2001–H, 121 FERC ¶ 61,289 (2007), order revising
41 Id. at 15–16. general concern about removing a hard filing requirements, Order No. 2001–I, FERC Stats.
42 Id. at 15 (citing PJM Market Monitor, cap in energy markets given potential & Regs. ¶ 31,282 (2008); Elec. Mkt. Transparency
Comments, Docket No. RM16–5–000, at 4 (filed concerns about market power in natural Provisions of Section 220 of the Fed. Power Act,
Apr. 4, 2016)). Order No. 768, FERC Stats. & Regs. ¶ 31,336 (2012),
43 Id. (citing ISO–NE Market Monitor, Comments,
gas markets. However, Order No. 831
order on reh’g, Order No. 768–A, 143 FERC ¶ 61,054
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Docket No. RM16–5–000, at 3 (filed Apr. 4, 2016)). did not remove a hard cap in energy (2013). They must also timely report to the
44 Id. at 17. markets—it adopted a $2,000/MWh Commission any change in status that would reflect
45 Id. at 8 (citing PSEG Energy Res. & Trade LLC a departure from the characteristics the Commission
v. FERC, 665 F.3d 203, 208 (D.C. Cir. 2011); Motor 47 Id. at 6–8 (citing Blumenthal v. FERC, 552 F.3d relied upon in granting their market-based rate
Vehicle Mfrs. Ass’n, 463 U.S. at 43; FCC v. Fox 875, 882–83 (D.C. Cir. 2009); FPC v. Texaco, 417 authority. 18 CFR 35.42 (2017).
Television Stations, 556 U.S. 502, 515 (2009)). U.S. 380, 399 (1974)). 51 See Order No. 831, FERC Stats. & Regs.
46 Id. at 5 (citing California ex rel. Lockyer v. 48 See Order No. 831, FERC Stats. & Regs. ¶ 31,387 at P 140 (‘‘[A]n RTO/ISO or a Market
FERC, 383 F.3d 1006, 1013–14 (9th Cir. 2004)). ¶ 31,387 at P 144. Continued
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As discussed above, the record According to TAPS, such behavior adjacent markets and sell that energy in
demonstrates that it is appropriate to would be difficult to monitor because the RTO/ISO energy market . . . it is
use expected costs in the verification of Order No. 831 does not require cost difficult for external resources in an
cost-based incremental energy offers information from external resources. adjacent market to withhold.’’ 61 The
because when actual costs are not TAPS therefore argues that, on hypothetical example TAPS presents in
known, a resource offer based on rehearing, the Commission should its request for rehearing does not
expected short-run marginal cost prevent import offers above $1,000/ persuade us otherwise. First, and as the
constitutes a competitive offer.52 In MWh from setting LMP in the importing Commission explained in Order No.
Order No. 831, the Commission stated RTO/ISO unless the import offer costs 831, it is unlikely that a resource-
that ‘‘[a] cost-based incremental energy are verified in advance, and that the
specific import transaction can
offer is based on the associated Commission should only permit uplift
successfully withhold energy from the
resource’s short-run marginal cost, payments to imports that have been
which constitutes a competitive offer cost-verified after-the-fact.55 destination market because any
free from the exercise of market resource-specific import transaction is
b. Determination also competing against an import
power.’’ 53 Therefore, the use of
expected costs in the verification 31. We deny TAPS’ request for transaction that simply buys from the
process does in fact allow the rehearing regarding the treatment of export market at the prevailing export
Commission to determine whether the imports. In Order No. 831, the market price. Second, the import offer
resulting market clearing prices would Commission found that exempting in that example would only benefit a
be just and reasonable. incremental energy offers from imports market participant that owns a fleet of
above $1,000/MWh from the verification internal and external generation (which
2. Verification of Imports requirement was justified because is online and being compensated at the
a. Request for Rehearing imports are not similarly situated to LMP in TAPS’ hypothetical example) if
30. TAPS seeks rehearing of Order No. internal resources.56 Because they are the import offer actually cleared the
831’s exemption of all imports from the not similarly situated, it was not importing RTO/ISO’s energy market.
verification requirement for incremental arbitrary or capricious to treat import However, such an import offer would
energy offers above $1,000/MWh and offers from external resources only clear this market at a price above
asserts that it is unjust and unreasonable differently than offers from internal
$1,000/MWh if it were below the
and arbitrary, and that it puts internal resources. Specifically, the Commission
verified cost-based incremental energy
and external resources on unequal found that internal resources and
imports are not similarly situated offers of other internal resources and
footing.54 According to TAPS, the below other import offers. Thus, such an
Commission’s finding that some imports because, based on the record,57 it may
be impossible to identify the costs import would be beneficial to the
are not resource-specific and therefore importing RTO/ISO market as it would
cannot have their costs verified does not underlying an import offer because they
are not resource-specific. Further, Order lower the clearing price compared to a
support exempting all imports from the
No. 831 remains consistent with current situation without it. Therefore, TAPS’
verification requirement. Therefore,
market power mitigation measures in example demonstrates that imports can
TAPS proposes that only resource-
specific imports whose costs are verified RTOs/ISOs that generally apply to lower an importing RTO/ISO’s LMP,
by the receiving RTO/ISO should be internal resources but not to imports. which supports the Commission’s
32. With respect to TAPS’ proposed rationale for allowing import offers
able to set LMP, while other imports
alternative which would prevent import above $1,000/MWh to set LMP.62 For
with offers above $1,000/MWh that are
offers above $1,000/MWh from setting these additional reasons, we find that
not verified should receive uplift
LMP if the costs cannot be verified, we the regulations regarding the treatment
payments if their costs are verified after-
reject it because, as supported in the of imports in Order No. 831 are just and
the-fact. TAPS further argues that failing
record,58 we continue to find that such reasonable and not arbitrary and
to verify the costs of imports presents a
a prohibition could discourage imports capricious and reject TAPS’ proposal to
greater opportunity and incentive for
at times when they are most needed to
generators to exercise market power. prevent import offers above $1,000/
provide additional supply and increased
TAPS presents a hypothetical example MWh from setting LMP in the importing
competition.59 Further, as the
of a market participant that owns RTO/ISO unless the import offer’s costs
Commission explained in Order No.
generators both inside and outside of an have been verified. For similar reasons,
831, such a prohibition could also result
RTO/ISO and asserts that such a market we deny TAPS’ proposal regarding
in uneconomic flows between RTOs/
participant could use its external uplift payments to imports. Finally, we
ISOs.60
generators to make import offers above note that in Order No. 831, the
33. In Order No. 831, the Commission
$1,000/MWh that its internal generators Commission stated it would consider
also considered market power concerns
would not be permitted to make. TAPS RTO/ISO proposals under FPA section
similar to those raised by TAPS in its
states that, if the market participant’s
rehearing request, but did not find that 205 to verify or otherwise review the
external resource sets the LMP in the
they warranted requiring cost- costs of imports or exports and/or
RTO/ISO (i.e., as an import), all of that
verification for import offers above develop additional mitigation
market participant’s internal resources
$1,000/MWh. The Commission provisions for import and export
would receive infra-marginal rents.
explained that because ‘‘market transactions with offers above $1,000/
participants can import energy from MWh.63
Monitoring Unit must verify that cost-based
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incremental energy offers above $1,000/MWh
55 Id. at 12–16.
reasonably reflect a resource’s actual or expected
56 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
costs.’’). 61 Id.
52 See supra P 22. P 195. P 196.
57 See, e.g., id. PP 180, 183, 185. 62 Order No. 831 does not apply to emergency
53 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at
P 83. 58 See, e.g., id. PP 179, 181, 188–189. purchases, such as emergency import purchases.
54 TAPS Request for Clarification/Rehearing at 59 Id. P 193. See id. P 198.
12–15. 60 Id. P 194. 63 Id. P 197.
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![53410 Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations
opportunity to recover those 43. Interested persons may obtain 47. User assistance is available for
opportunity costs through an uplift information on the reporting eLibrary and the FERC’s Web site during
payment, subject to verification. We requirements by contacting: Federal normal business hours from FERC
further clarify that a resource may not Energy Regulatory Commission, 888 Online Support at 202–502–6652 (toll
receive uplift payments for incremental First Street NE., Washington, DC 20426 free at 1–866–208–3676) or email at
energy costs in excess of the costs [Attention: Ellen Brown, Office of the ferconlinesupport@ferc.gov, or the
included in its verified incremental Executive Director, email: Public Reference Room at (202) 502–
energy offer. That is, a resource may not DataClearance@ferc.gov, phone: (202) 8371, TTY (202)502–8659. Email the
submit a cost-based incremental energy 502–8663, fax: (202) 273–0873]. Public Reference Room at
offer based on expected costs prior to Comments concerning the requirements public.referenceroom@ferc.gov.
the market clearing process and of this rule may also be sent to the
subsequently receive uplift payments to VI. Effective Date
Office of Information and Regulatory
make it whole to an offer above the Affairs, Office of Management and 48. These regulations are effective
$/MWh level(s) of its offer(s).70 In this Budget, Washington, DC 20503 January 16, 2018.
instance, allowing a resource to receive [Attention: Desk Officer for the Federal List of Subjects in 18 CFR Part 35
uplift in excess of its verified cost-based Energy Regulatory Commission]. For
incremental energy offer could give that security reasons, comments should be Electric power rates, Electric utilities,
resource the incentive to submit offers sent by email to OMB at oira_ Non-discriminatory open access
that do not reflect its actual short-run submission@omb.eop.gov. Comments transmission tariffs.
marginal costs and could thus result in submitted to OMB should refer to By the Commission.
inefficient resource selection. FERC–516C and OMB Control Number Issued: November 9, 2017.
40. Further, such after-the-fact uplift 1902–0287. Nathaniel J. Davis, Sr.,
payments may not include any adders
above cost, including risk related IV. Regulatory Flexibility Act Deputy Secretary.
adders, because actual costs are known Certification Regulatory Text
after-the-fact.71 This finding is 44. The Regulatory Flexibility Act of
consistent with Commission precedent In consideration of the foregoing, the
1980 (RFA) 75 generally requires a Commission amends part 35, chapter I,
regarding PJM’s requests for waivers of description and analysis of rules that
certain tariff provisions related to its title 18, Code of Federal Regulations, as
will have significant economic impact follows:
offer cap.72 on a substantial number of small
III. Information Collection Statement entities. The RFA does not mandate any PART 35—FILING OF RATE
particular outcome in a rulemaking. It SCHEDULES AND TARIFFS
41. The Paperwork Reduction Act
only requires consideration of
(PRA) 73 requires each federal agency to ■ 1. The authority citation for part 35
alternatives that are less burdensome to
seek and obtain Office of Management continues to read as follows:
small entities and an agency
and Budget (OMB) approval before
explanation of why alternatives were Authority: 16 U.S.C. 791a–825r, 2601–
undertaking a collection of information
rejected. The Commission has 2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
directed to ten or more persons or
determined that there will not be a
contained in a rule of general ■ 2. Revise § 35.28(g)(9) to read as
significant impact on a substantial
applicability. OMB’s regulations,74 in follows:
number of small entities, therefore these
turn, require approval of certain
requirements under the RFA do not § 35.28 Non-discriminatory open access
information collection requirements
apply. transmission tariff.
imposed by agency rules.
42. The Commission is amending its V. Document Availability * * * * *
regulations to clarify what the (g) * * *
45. In addition to publishing the full (9) A resource’s incremental energy
Commission already required in Order
text of this document in the Federal offer must be capped at the higher of
No. 831—that either actual or expected
Register, the Commission provides all $1,000/MWh or that resource’s cost-
costs included in incremental energy
interested persons an opportunity to based incremental energy offer. For the
offers above $1,000/MWh may be
view and/or print the contents of this purpose of calculating Locational
submitted for verification. The
document via the Internet through Marginal Prices, Regional Transmission
Commission estimates that there will be
FERC’s Home Page (http:// Organizations and Independent System
no net change to burden.
www.ferc.gov) and in FERC’s Public Operators must cap cost-based
70 For example, a resource may not submit a Reference Room during normal business incremental energy offers at $2,000/
$2,300/MWh offer based on expected short-run hours (8:30 a.m. to 5:00 p.m. Eastern MWh. The actual or expected costs
marginal cost that is verified and clears the market time) at 888 First Street NE., Room 2A, underlying a resource’s cost-based
and receive uplift associated with incremental Washington DC 20426.
energy costs above $2,300/MWh, even if that
incremental energy offer above $1,000/
resource’s actual short-run marginal cost, based on 46. From FERC’s Home Page on the MWh must be verified before that offer
an after-the-fact review, is $2,500/MWh. Internet, this information is available on can be used for purposes of calculating
71 Order No. 831, FERC Stats. & Regs. ¶ 31,387 at eLibrary. The full text of this document Locational Marginal Prices. If a resource
P 146. is available on eLibrary in PDF and submits an incremental energy offer
72 In the 2015 PJM offer cap order, the
Microsoft Word format for viewing, above $1,000/MWh and the actual or
Commission found that ‘‘the 10 percent adder
nshattuck on DSK9F9SC42PROD with RULES
[above costs] is unjust and unreasonable as applied printing, and/or downloading. To access expected costs underlying that offer
to ex post review of documented costs, because the this document in eLibrary, type the cannot be verified before the market
cost [sic] are no longer uncertain.’’ See PJM docket number excluding the last three clearing process begins, that offer may
Interconnection L.L.C., 153 FERC ¶ 61,289, at P 31 digits of this document in the docket
(2015). See also PJM Interconnection, L.L.C., 149
not be used to calculate Locational
FERC ¶ 61,059, at P 13 (2014). number field. Marginal Prices and the resource would
73 44 U.S.C. 3501–3520. be eligible for a make-whole payment if
74 5 CFR 1320 (2017). 75 5 U.S.C. 601–12. that resource is dispatched and the
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![Federal Register / Vol. 82, No. 220 / Thursday, November 16, 2017 / Rules and Regulations 53411
resource’s actual costs are verified after- with the Federal regulations. See 30 August 15, 2011 (76 FR 50436). In the
the-fact. A resource would also be U.S.C. 1253(a)(1) and (7). On the basis same document, we opened the public
eligible for a make-whole payment if it of these criteria, the Secretary of the comment period and provided an
is dispatched and its verified cost-based Interior conditionally approved the opportunity for a public hearing or
incremental energy offer exceeds Kentucky program on May 18, 1982. meeting. We did not hold a public
$2,000/MWh. All resources, regardless You can find background information hearing or meeting because no one
of type, are eligible to submit cost-based on the Kentucky program, including the requested one. The public comment
incremental energy offers in excess of Secretary’s findings, the disposition of period ended on September 14, 2011.
$1,000/MWh. comments, and conditions of approval We received comments from two
[FR Doc. 2017–24803 Filed 11–15–17; 8:45 am] of the Kentucky program in the May 18, organizations.
BILLING CODE 6717–01–P
1982, Federal Register (47 FR 21404, III. OSMRE’s Findings
21434). You can also find later actions
concerning Kentucky’s program and The following are the findings we
program amendments at 30 CFR 917.11, made concerning Kentucky’s proposed
DEPARTMENT OF THE INTERIOR amendment under SMCRA at Section
917.12, 917.13, 917.15, 917.16, and
917.17. 509, 30 U.S.C. 1259 and the Federal
Office of Surface Mining Reclamation
regulations at 30 CFR 800.14 and
and Enforcement II. Description of the Proposed 800.15.
Amendment
30 CFR Part 917 KRS 350.060 (11) Processing Permit
On May 10, 2011, Kentucky submitted Applications
[KY–254–FOR; OSM–2011–0005; an amendment to OSMRE for approval
S1D1SSS08011000SX064A000189S180110; that proposed bonding revisions to the The new language in KRS 350.060
S2D2SSS08011000SX066A00018XS501520] KRS as authorized by HB 385, which (11) is intended to ensure that bond
passed during the State’s regular 2011 protocol regulations include the formula
Kentucky Regulatory Program for establishing the amount of the bond.
legislative session. HB 385 was passed
AGENCY: Office of Surface Mining in response to OSMRE’s findings in its Failure to do so would result in any
Reclamation and Enforcement (OSMRE), January 5, 2011, National Priority administrative regulations or bonding
Interior. Oversight Evaluation of the Adequacy of requirements to be declared deficient
Kentucky Reclamation Performance automatically, in accordance with KRS
ACTION: Final rule; approval of
Bond Amounts (National Oversight Chapter 13A.
amendment. While these proposed State revisions
Study) report. In that report, OSMRE
SUMMARY: We are approving an oversight and programmatic reviews have no direct Federal counterparts
amendment to the Kentucky regulatory identified that current reclamation there is no provision in SMCRA or its
program (hereinafter, the ‘‘Kentucky performance bonds in Kentucky are not implementing regulations that prohibits
program’’) under the Surface Mining sufficient to complete the reclamation a State from requiring its bond protocols
Control and Reclamation Act of 1977 required in approved permits. On to be implemented solely as regulations.
(SMCRA or the Act). Kentucky February 3, 2011, the Kentucky On their face, the proposed revisions are
submitted a proposed amendment to Department for Natural Resources not inconsistent with Section 509 of
OSMRE that includes revisions to the (KYDNR) and OSMRE signed an Action SMCRA and 30 CFR 800.14, and we are
Kentucky Revised Statutes (KRS) as Plan detailing the steps necessary for therefore approving them, as noted
authorized by House Bill 385 (HB 385), correcting identified bond calculation below.
regarding bonding of surface coal While HB 385 could be construed to
deficiencies. The Action Plan required
mining and reclamation operations. require the KYDNR to implement all
KYDNR to complete revised bonding
bond adjustments as regulations before
DATES: The effective date is December protocols by April 1, 2011, along with
the adjustments can be made, to do so
18, 2017. a timetable for implementation for new
would be inconsistent with the literal
FOR FURTHER INFORMATION CONTACT: and existing permits. HB 385 amends
construction of the language of the bill.
Robert Evans, Telephone: (859) 260– Kentucky Revised Statutes 350.060 to
Therefore, we do not construe HB 385
3900. Email: bevans@osmre.gov. provide that:
to apply to individual bonding
SUPPLEMENTARY INFORMATION: Within thirty (30) days of a cabinet adjustments, or other individual
determination of a need to change a bond bonding decisions.
I. Background on the Kentucky Program protocol currently in use, the cabinet shall
II. Description of the Amendment Rather, we are approving the
immediately promulgate administrative
III. OSMRE’s Findings regulations setting forth bonding proposed amendment, in accordance
IV. Summary and Disposition of Comments requirements including, but not limited to, with its plain language, which will not
V. OSMRE’s Decision requirements for the amount, duration, impede implementation of the
VI. Procedural Determinations release, and forfeiture of bonds. Bond requirement in Section 509 of SMCRA
protocols shall not be exempt from KRS that ‘‘[t]he amount of the bond shall be
I. Background on the Kentucky 13A.100 and shall be established by sufficient to assure the completion of
Program promulgating administrative regulations the reclamation plan if the work had to
under KRS Chapter 13A. Failure to include
Section 503(a) of the Act permits a the formula for establishing the amount of
be performed by the regulatory authority
State to assume primacy for the the bond in any administrative regulation on in the event of forfeiture.’’ Nor will the
regulation of surface coal mining and bonding requirements shall be deemed a proposed amendment impede the
nshattuck on DSK9F9SC42PROD with RULES
reclamation operations on non-Federal failure to comply with the prescriptions of obligation of the regulatory authority to
and non-Indian lands within its borders this section and the administrative regulation adjust the amount of bond in
by demonstrating that its program shall automatically be declared deficient in accordance with 30 CFR 800.15. Should
includes, among other things, State laws accordance with KRS Chapter 13A. we find, however, during oversight, that
and regulations that govern surface coal We announced receipt of the the amendment is being interpreted in
mining and reclamation operations in amendment and asked for comments in a manner that would render it
accordance with the Act and consistent a Federal Register notice published on inconsistent with either Section 509 of
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Document Created: 2017-11-16 03:52:56
Document Modified: 2017-11-16 03:52:56
| Category | Regulatory Information | |
| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
| Publisher | Office of the Federal Register, National Archives and Records Administration | |
| Section | Rules and Regulations | |
| Action | Order on rehearing and clarification. | |
| Dates | This rule is effective January 16, 2018. | |
| 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, [email protected] Pamela Quinlan (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-6179, [email protected] Anne Marie Hirschberger (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8387, [email protected] | |
| FR Citation | 82 FR 53403 | |
| CFR Associated | Electric Power Rates; Electric Utilities and Non-Discriminatory Open Access Transmission Tariffs |
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