2019-15716. Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets

Issued July 18, 2019.

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is modifying its regulations regarding the horizontal market power analysis required for market-based rate sellers that study certain Regional Transmission Organization (RTO) or Independent System Operator (ISO) markets and submarkets therein. This modification relieves such sellers of the obligation to submit indicative screens to the Commission in order to obtain or retain authority to sell energy, ancillary services and capacity at market-based rates. The Commission's regulations continue to require market-based rate sellers that study an RTO, ISO, or submarket therein, to submit indicative screens for authorization to make capacity sales at market-based rates in any RTO/ISO market that lacks an RTO/ISO-administered capacity market subject to Commission-approved RTO/ISO monitoring and mitigation. For those RTOs and ISOs that do not have an RTO/ISO-administered capacity market, Commission-approved RTO/ISO monitoring and mitigation is no longer presumed sufficient to address any horizontal market power concerns for capacity sales where there are indicative screen failures. Sellers studying RTO/ISO markets that do not have an RTO/ISO-administered capacity market would be relieved of the requirement to submit indicative screens to the Commission if they sought market-based rate authority limited to sales of energy and/or ancillary services in those markets.

DATES:

This rule will become effective September 24, 2019.

FOR FURTHER INFORMATION CONTACT:

Ashley Dougherty (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, [phone]

Mary Ellen Stefanou (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, [phone]

SUPPLEMENTARY INFORMATION:

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Neil Chatterjee, Chairman; Cheryl A. LaFleur, Richard Glick, and Bernard L. McNamee.

Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets

Docket No. RM19-2-000

Order No. 861

Final Rule

(Issued July 18, 2019)

Table of Contents

	Paragraph Nos.
I. Introduction	1
II. Background	5
III. Discussion	9
A. Assurance of Just and Reasonable Rates	9
1. Availability of Data Necessary for Effective Review of Seller Market Power	10
2. No Sub-delegation of Statutory Responsibility	28
B. Retention of Screens for Capacity Sellers in CAISO and SPP	32
1. CAISO	32
2. SPP	43
C. Clarifications for Capacity Sellers in CAISO and SPP	49
D. Retention of Screens for EIM	53
1. Comments	53
2. Commission Determination	56
E. Bilateral Sales	57
1. Comments	57
2. Commission Determination	59
F. Current Status and Effectiveness of RTO/ISO Monitoring and Mitigation	63
1. Comments	63
2. Commission Determination	65
G. Other Issues Raised By Commenters	67
1. Change in Status and Triennial Updates	67
2. Rights of Market Monitors	73
3. Corporate Character Reporting	77
4. Data Collection NOPR and Market Power NOI	79
IV. Information Collection Statement	81
V. Environmental Analysis	89
VI. Regulatory Flexibility Act	90
VII. Document Availability	97
VIII. Effective Date and Congressional Notification	100

I. Introduction

1. On December 20, 2018, the Federal Energy Regulatory Commission (Commission) issued a notice of proposed rulemaking (NOPR) ^[1] proposing to modify § 35.37(c) of its regulations regarding the horizontal market power analysis for market-based rate sellers ^[2] studying certain Regional Transmission Organization (RTO) and Independent System Operator (ISO) markets.^[3] The proposed modification would relieve Sellers of the requirement to submit indicative screens to the Commission in order to obtain or retain authority to sell energy, ancillary services and capacity at market-based rates when studying RTO/ISO markets with RTO/ISO-administered energy, ancillary services, and capacity markets that are subject to Commission-approved RTO/ISO monitoring and mitigation. Under the proposal, the Commission did not propose to relieve Sellers studying RTOs or ISOs that do not have an RTO/ISO-administered capacity market from submitting indicative screens to sell capacity in those markets at market-based rates. However, under the proposal Sellers studying such markets would be relieved of the requirement to submit indicative screens to the Commission if they sought market-based rate authority limited to sales of energy and/or ancillary services in those markets.^[4]

2. The Commission also proposed to eliminate the rebuttable presumption that Commission-approved RTO/ISO market monitoring and mitigation is sufficient to address any horizontal market power concerns regarding sales of capacity in RTOs/ISOs that do not have an RTO/ISO-administered capacity market.

3. The Commission received 18 comments in response to the NOPR.^[5] A list of commenters and the abbreviated names used in this final rule is attached as Appendix A.

4. In this final rule, we adopt the proposal from the NOPR and provide clarification, as discussed below.

II. Background

5. The Commission allows power sales at market-based rates if the Seller and its affiliates do not have, or have adequately mitigated, horizontal and vertical market power.^[6] Section 35.37 of the Commission's regulations requires market-based rate Sellers to submit indicative screens as part of a market power analysis: (1) When seeking market-based rate authority; (2) every three years for Category 2 Sellers; ^[7] and (3) at any other time the Commission requests a Seller to submit an analysis.

6. In Order No. 697, the Commission adopted two indicative screens for assessing horizontal market power: The pivotal supplier screen and the wholesale market share screen.^[8] The Commission has stated that passing both screens establishes a rebuttable presumption that the Seller does not possess horizontal market power, while failing either screen creates a rebuttable presumption that the Seller has horizontal market power.^[9] Generally, Sellers that are located in and are members of an RTO/ISO may consider the geographic area under the control of the RTO/ISO as the default relevant geographic market for purposes of the indicative screens.^[10] In Order No. 697-A, the Commission adopted a rebuttable presumption that existing RTO/ISO mitigation is sufficient to address any market power concerns created by indicative screen failures in an RTO/ISO.^[11]

7. On July 19, 2014, in a NOPR that culminated in the issuance of Order No. 816,^[12] the Commission proposed certain changes and clarifications in order to streamline and improve the market-based rate program's processes and procedures.^[13] Specifically, as relevant for the purposes of the instant rulemaking, the Commission proposed in the Order No. 816 NOPR to allow Sellers in RTO/ISO markets to address horizontal market power issues in a streamlined manner that would not involve the submission of indicative screens if the Seller relies on Commission-approved monitoring and mitigation to prevent the exercise of market power.^[14] Under that proposal, RTO/ISO sellers ^[15] would state that they are relying on such monitoring and mitigation to address the potential for market power issues that they might have, provide an asset appendix, and describe their generation and transmission assets. The Commission would retain its ability to require a market power analysis, including indicative screens, from any Seller at any time.^[16]

8. When the Commission issued Order No. 816, it stated that it was not prepared at that time to adopt the proposal regarding RTO/ISO sellers, but that it would further consider the issues raised by commenters and transferred the record on that issue to Docket No. AD16-8-000 for possible consideration in the future as the Commission may deem appropriate.^[17] The Commission reviewed and considered that record in preparing the NOPR proposal.

III. Discussion

A. Assurance of Just and Reasonable Rates

9. In proposing to relieve RTO/ISO sellers of the requirement to submit indicative screens to the Commission in markets with RTO/ISO-administered energy, ancillary services, and capacity markets subject to Commission-approved monitoring and mitigation, the Commission emphasized that it would continue to ensure that market-based rates are just and reasonable.^[18] However, commenters raise concerns that the proposal compromises the Commission's ability to ensure just and reasonable rates because, they argue, it eliminates data necessary for detecting the presence of market power, and it results in an improper sub-delegation of the Commission's statutory responsibility to the RTO/ISO.^[19] We have carefully considered these arguments, but disagree for the reasons discussed below. Accordingly, we adopt the changes to § 35.37(c) of the Commission's regulations, as proposed in the NOPR.

1. Availability of Data Necessary for Effective Review of Seller Market Power

a. Comments

10. Opponents of the NOPR raise concerns that the proposal would deprive the Commission and intervenors/complainants of data that is necessary for assessing market power. They add that the proposal is contrary to the Commission's statement in Order No. 697-A that, even where RTO/ISO monitoring and mitigation is in place, the indicative screens provide “critical information regarding the potential market power of Sellers in the market.” ^[20]

11. TAPS and AAI/APPA/NRECA both state that the courts have relied on ex ante market power screening in upholding the Commission's use of market-based rates, and both argue that the indicative screens play an essential role in the Commission's ex ante market power analysis, which “consists of a finding that the applicant lacks market power (or has taken sufficient steps to mitigate market power).” ^[21] TAPS argues that the “rigorous screening process to detect market power” and collection of seller-specific data were critical to the court's upholding of the Commission's market-based rate program in Order No. 697.^[22] Similarly, AAI/APPA/NRECA argue that courts have specifically relied on the existence of seller-specific, ex ante market power screening in upholding the Commission's use of market-based rates.^[23]

12. TAPS and AAI/APPA/NRECA argue that the efficacy of the other existing market-based rate requirements and procedural avenues would be undermined by the elimination of the indicative screens. For example, TAPS notes that the Commission and others may always scrutinize a Seller's asset appendix, but the indicative screens enable them to better understand this information in the context of particular markets.^[24] Similarly, AAI/APPA/NRECA note that a Seller's asset appendix and affiliate information offer “a ballpark idea of the share of generation capacity owned or controlled by a [S]eller and its affiliates” but is “divorced from any analytical framework designed to identify a [S]eller's ability to exercise market power.” ^[25] AAI/APPA/NRECA also state that the proposal would deprive the Commission of important data and analysis that is complementary to the Commission's merger analysis, transmission policy, and policies relating to certification of natural gas pipelines that also have interests in generation assets.^[26]

13. AAI/APPA/NRECA and TAPS argue that the Commission should retain its case-by-case approach for determining whether market power mitigation is sufficient to address market power concerns.^[27] TAPS explains that “[e]ven in those instances where, based on RTO monitoring and mitigation, the Commission has ultimately granted [market-based rate] authority despite screen failures, it nevertheless has done so with at least an initial understanding of the degree of potential market power the particular [S]eller may have.” ^[28]

14. Public Citizen believes that the NOPR interferes with the public's right to inspect, comment, and protest Federal Power Act (FPA) section 205 ^[29] rate filings such that “at the time of a [s]ection 205 [market-based rate] application, any member of the public with concerns about market power wielded by the applicant would now be required to lodge their challenge with the relevant RTO tariff in a completely different proceeding.” ^[30]

15. While recognizing that market monitors are required under Order No. 719 to submit annual and quarterly reports, AAI/APPA/NRECA state that the reporting requirements are not uniform and are left to the discretion of the RTO/ISO monitor.^[31] In particular, they note that the market monitors are not obligated to collect and report individual entity market shares and market concentration data.

16. TAPS asserts that the lack of indicative screen information will hinder the ability of affected parties and the Commission to meet the evidentiary burden required to challenge market-based rate filings.^[32] AAI/APPA/NRECA share this concern and believe that the NOPR increases the burden for entities seeking to challenge a Seller's market-based rate authority. They note that under the current framework, the sufficiency of RTO/ISO market monitoring and mitigation is only placed at issue after a Seller fails one or both of the indicative screens, resulting in a presumption that the Seller has market power. In contrast, under the proposal, a party challenging market-based rate authority would be required to demonstrate, as a threshold matter, that the Seller has market power.^[33]

b. Commission Determination

17. At the outset, we note that the Commission's prior decision in Order No. 697-A to retain the indicative screens for Sellers in RTO/ISO markets is not controlling here. The Commission may evaluate the continuing reasonableness of a prior policy or determination and subsequently reach a different conclusion.^[34] We reach a different conclusion here in part based on our finding that the proposal does not eliminate data necessary for the effective review of a Seller's market power.

18. We also disagree with TAPS and AAI/APPA/NRECA's assertion that the courts, in upholding the Commission's ability to approve market-based rates, have found that indicative screens play an essential role in the Commission's ex ante analysis. While the courts have found that an ex ante finding of the absence of market power, coupled with sufficient post-approval reporting requirements, ensures that market-based rates are just and reasonable, the courts have recognized that the Commission's market-based rate analysis looks at whether a seller lacks market power or has taken sufficient steps to mitigate it.^[35] The use of indicative screens is not the only permissible approach the Commission may employ to assess market power before authorizing market-based rates, nor are indicative screens essential to the Commission's determination of whether market power is mitigated.

19. Contrary to AAI/APPA/NRECA's assertion, the Commission is not “distancing itself” from oversight of competitive issues arising in wholesale markets. Sellers continue to be required to submit notices of change in status and market power analyses, which include a demonstration regarding vertical market power, affiliate information, and an asset appendix. Additionally, Sellers continue to be required to submit Electric Quarterly Reports (EQR). EQR reporting is a vital tool for determining whether Sellers may be exercising market power because it shows the volumes and prices at which Sellers are transacting; as such, it can be used to determine a Seller's market share of sales and relative prices.

20. We are not aware of an instance to date where an intervenor or complainant has used indicative screen data as part of a challenge to the market power of an RTO/ISO seller. Nevertheless, even without the screen data, the information that continues to be required under § 35.37 is useful to those seeking to challenge a Seller's market-based rate authority. We disagree with TAPS's suggestion that this information is of limited value without the indicative screens. The asset appendices also provide detailed information on a Seller's generation portfolio, including affiliated generation and long-term power purchase agreements. Through the triennial update process,^[36] a potential intervenor can review contemporaneous information on a Seller's generation portfolio and can aggregate this information to get an indication of an individual Seller's size relevant to the market. Moreover, data on total market size is available from other public sources such as reports from the U.S. Energy Information Administration.

21. Public Citizen is mistaken in its view that challengers to a market-based rate filing would have to lodge their objections with the relevant RTO/ISO tariff in a different proceeding.^[37] Any objections to a Seller's market-based rate authority can and should occur as a direct response to an initial application, a change in status filing, a triennial update, or in a proceeding instituted under FPA section 206.^[38] The Commission will consider all relevant information in the record when determining whether the Seller can obtain or retain market-based rate authority. This will continue to occur notwithstanding the existence of Commission-approved monitoring and mitigation.

22. The public and the Commission will continue to have access to a Seller's ownership information, vertical market power analysis, asset appendix, and EQRs, as well as to the market monitors' reports. For example, PJM IMM notes that its quarterly State of the Market reports contain a comprehensive listing of market power concerns.^[39] Anyone may use this information in support of a challenge to a Seller's market-based rate authority. The Commission would then consider this and other information to determine whether the Seller may obtain or retain market-based rate authority. In addition, contrary to Public Citizen's argument that “once [market-based rate] authority is granted, [the Commission] is unlikely to take it away,” the standard for obtaining and retaining market-based rate authority is the same. The Commission can and does institute FPA section 206 proceedings when potential market power concerns arise.^[40]

23. In addition, the Commission conducts independent, ex post analyses using public and non-public data to assess market behavior in RTO/ISO markets. The Commission can examine transaction level data (e.g., resource supply offers) using data provided pursuant to Order No. 760 to conduct such oversight.^[41]

24. Regarding concerns that the market monitors' reports are not “uniform,” we note that the RTOs/ISOs themselves are not uniform and that a “one size fits all” report format is unnecessary. The more relevant question is whether the reports contain a comprehensive review of market performance. To the extent intervenors/complainants identify relevant information the reports are lacking, they can raise such concerns as part of a challenge to a Seller's market-based rate authority and request that the Commission require the Seller to submit indicative screens.

25. We acknowledge that, under the proposal that we adopt herein, a successful challenge to Seller's market-based rate authority will involve two demonstrations: (1) That the Seller has market power and (2) that such market power is not addressed by existing Commission-approved RTO/ISO market monitoring and mitigation.

26. Regarding the second demonstration, a challenge to existing Commission-approved RTO/ISO market monitoring and mitigation would be no different than what the Commission articulated in Order No. 697-A, where it established the rebuttable presumption that Commission-approved market monitoring and mitigation was sufficient to address market power concerns. There, the Commission explicitly recognized that “intervenors may challenge that presumption. Depending on the nature of the evidence submitted by an intervenor, the Commission will consider whether to institute a separate FPA section 206 proceeding to investigate whether the existing RTO/ISO mitigation continues to be just and reasonable.” ^[42]

27. With respect to the first demonstration as to whether a Seller has market power, we are sympathetic to the concern that, to the extent intervenors/complainants successfully rebut the presumption as to the sufficiency of market monitoring and mitigation, they will not have indicative screen information which would otherwise have established a presumption of market power one way or the other. In this situation, the Commission retains authority to require the Seller to submit indicative screens or other evidence to help evaluate whether the Seller has market power.

2. No Sub-Delegation of Statutory Responsibility

a. Comments

28. Opponents of the proposal renew many of the legal arguments raised in the Order No. 816 proceeding. AAI/APPA/NRECA argue that RTOs/ISOs cannot lawfully substitute for the Commission's regulation of wholesale electricity markets required by the FPA. They assert the RTOs/ISOs are not public agencies or regulators and cannot serve as the Commission's surrogate. Similarly, Public Citizen contends that the proposal weakens oversight by transferring regulatory control to private consulting firms (referring specifically to the market monitors).^[43]

29. AAI/APPA/NRECA point to a recent Court of Appeals for the District of Columbia Circuit (D.C. Circuit) opinion where the court “emphasized the distinction between the PJM IMM, which `is not a creature of statute and operates under no affirmative duty imposed by public law,' and a public regulator such as the Commission.” ^[44] AAI/APPA/NRECA also point to the D.C. Circuit's opinion in Exelon Corp. v. FERC, issued eight days after the NOPR, and its holding “that only the Commission—not the ISO or its market monitor—had authority to evaluate whether a capacity Seller's offer was just and reasonable under the FPA or instead constituted unlawful physical withholding and should be subject to mitigation.” ^[45]

b. Commission Determination

30. We agree that it is the Commission, and not the market monitors or the RTOs/ISOs, that bears responsibility for ensuring that rates are just and reasonable under the FPA. Under the proposal, which we adopt in this final rule, it is the Commission—and not the RTO/ISO or its associated market monitor—that determines whether an entity can obtain or retain market-based rate authority. In performing mitigation, the RTO/ISO or market monitor does not usurp the Commission's role or act as its surrogate but rather implements Commission-approved tariff provisions. Thus, the Commission is the entity determining whether granting a Seller market-based rate authority would result in just and reasonable rates.

31. The Exelon case relied on by AAI/APPA/NRECA is inapposite to this rulemaking. That proceeding involved a disputed tariff provision under which the ISO New England Inc. market monitor would review a capacity supplier's retirement bid and, if it determined that the bid was unsupported, would substitute a “mitigated” bid that would then be submitted to the Commission for approval under FPA section 205. On remand from the D.C. Circuit, the Commission explained that its review of an FPA section 205 filing would consider the entirety of the record and that it would accept the capacity supplier's bid so long as the capacity supplier persuades the Commission that its bid is just and reasonable, despite contrary assertions by the market monitor.^[46] Nothing in Exelon calls into question the Commission's ability to rely on Commission-approved RTO/ISO monitoring and mitigation market rules to address market power concerns. The Commission will continue to review a Seller's filing under FPA section 205 based on the entirety of the record and will grant market-based rate authority if the Seller demonstrates that it lacks the ability to exercise market power.

B. Retention of Screens for Capacity Sellers in CAISO and SPP

1. CAISO

a. Comments

32. Several commenters request extending the proposal to grant relief from submitting the indicative screens to capacity Sellers in the CAISO market, while other commenters support the Commission's proposal to retain the requirement that Sellers submit indicative screens for capacity sales in CAISO.

33. Calpine, EEI, Indicated Generation Investors, PG&E, Competitive Suppliers, and SoCal Edison urge the Commission to extend the proposal to grant relief from submitting the indicative screens to capacity sellers in CAISO.^[47] Calpine identifies “structural safeguards” in California that protect against the exercise of horizontal market power in the sale of capacity. Calpine explains that these safeguards are provided through the combination of the California Public Utilities Commission (CPUC)-administered Resource Adequacy program, CAISO Tariff requirements imposed on sellers of Resource Adequacy capacity and, ultimately, on CAISO-administered backstop capacity procurement programs, including the Capacity Procurement Mechanism and Reliability Must-Run Agreements. Calpine argues that the Commission-approved settlement for the bid cap in the capacity backstop market establishes “presumptively just and reasonable price caps for capacity, even in a competitive market.” ^[48]

34. Competitive Suppliers maintain that “[b]etween [Capacity Procurement Mechanism] to address capacity deficiency issues when they arise, and the [Reliability Must-Run] process to mandate service from units that would otherwise retire, CAISO has backstop mechanisms that cap prices—initially at a representation of going forward fixed costs in the case of [Capacity Procurement Mechanism], and ultimately at full cost-of-service with [Reliability Must-Run].” ^[49] Competitive Suppliers also suggest that the Commission could extend its ruling in Order No. 784,^[50] which permits a Seller to make market-based sales of certain ancillary services if the sale results from a competitive solicitation, to sales of capacity in CAISO. Competitive Suppliers propose, consistent with the process specified in Order No. 784, that a Seller be allowed to make market-based sales of capacity in CAISO if it demonstrates that the sale of capacity results from a competitive solicitation that meets the guidelines articulated in Order No. 784 (transparency, definition, evaluation, oversight, and competitiveness).

35. SoCal Edison states that while CAISO does not have a centralized capacity market, the CPUC and CAISO together have designed and implemented a Resource Adequacy framework, which provides similar monitoring and mitigation measures found in centralized capacity markets.^[51] SoCal Edison argues that although CAISO is currently evaluating its Reliability Must-Run and Capacity Procurement Mechanism processes, such changes should not be viewed as an indication that the current processes are inferior to the Commission's horizontal market power screens.^[52] SoCal Edison states that if the Commission does not eliminate the requirement for Sellers to submit indicative screens for capacity sales in CAISO, it recommends a technical conference to consider how CAISO's market monitoring and mitigation of capacity sales can be modified such that the requirement to submit indicative screens can be eliminated prior to the submission of the next triennial for the Southwest region due in December 2021, or how the indicative screens can be modified to reflect the Resource Adequacy reserve margin obligations and capacity procurement in CAISO.^[53]

36. Other commenters support the proposal to retain the requirement that Sellers submit indicative screens for capacity sales in CAISO.^[54] CAISO DMM “strongly supports the NOPR's provisions relating to capacity market sales in the CAISO” ^[55] and notes that a bilateral capacity sales market that supports resource adequacy is overseen by the CPUC, but it is not directly subject to Commission-approved RTO/ISO monitoring. CAISO DMM explains that CAISO's backstop procurement processes help to set a ceiling on resources' bilateral capacity contract compensation, similar to the way system-wide offer caps set ceilings in ISO-administered capacity markets; “[h]owever, these backstop procurement processes do not mitigate market power like the Commission-approved market power mitigation in those capacity markets.” ^[56]

37. TAPS comments that the indicative screens are especially important for capacity sales in RTOs that do not administer a capacity market because “there is no basis for presuming the sufficiency of monitoring and mitigation absent Commission-approval of particular measures for the specific market.” ^[57] TAPS also supports the proposal to eliminate the rebuttable presumption that RTO market monitoring and mitigation is sufficient with respect to capacity sales where there is no RTO/ISO administered capacity markets.^[58]

b. Commission Determination

38. We adopt the NOPR proposals to require capacity sellers in CAISO to continue to submit indicative screens and to eliminate the rebuttable presumption that Commission-approved RTO/ISO market monitoring and mitigation is sufficient to address any horizontal market power concerns regarding sales of capacity in CAISO.

39. Although the majority of capacity sales within CAISO are made through the Resource Adequacy program, we note that these sales are not reviewed, approved, or monitored by CAISO. The CPUC reviews and approves capacity purchases by load serving entities via the Resource Adequacy program pursuant to resource requirements established by the CPUC, but these purchases are not necessarily the result of competitive solicitations. There is no transparent market price determined under Commission-approved rules for capacity in CAISO comparable to the market price for capacity established by RTOs/ISOs with centralized capacity markets.^[59]

40. With regard to the soft offer cap for the Capacity Procurement Mechanism cited by Calpine and other commenters, we note that the soft offer cap is an estimate of the cost of new entry and does not necessarily reflect a mitigated, “going forward” cost of any existing generator and does not address concerns regarding local market power. Although the soft offer cap is helpful, it does not provide mitigation comparable to the mitigation applied in the RTO/ISO administered capacity markets.

41. We disagree with Competitive Suppliers' comment that a Seller be allowed to make market-based rate sales of capacity in CAISO if it demonstrates that the sale of capacity results from a competitive solicitation that meets the guidelines articulated in Order No. 784 ((1) transparency; (2) definition; (3) evaluation; (4) oversight; and (5) competitiveness) as a meaningful alternative to the requirement to submit screens. Order No. 784 describes an auction process that, if satisfied, would enable a Seller to sell certain ancillary services at market-based rates on a case-by-case basis.^[60] The first four guidelines comprise the Edgar-Allegheny ^[61] guidelines that must be adequately addressed for Commission acceptance of an affiliate sale. Order No. 784 established an additional criteria—competitiveness. To meet the competitiveness criteria, sellers are required to submit evidence showing the absence of market power in the ancillary service market. Therefore, were the Order No. 784 guidelines applied here, a Seller would be obligated to submit screens, a comparable study, or other evidence that demonstrates a lack of market power in the capacity market to comply with the competitiveness guideline.

42. Lastly, we do not think it is necessary to hold a technical conference to consider how CAISO's market monitoring and mitigation of capacity sales can be modified such that the requirement to submit indicative screens can be eliminated prior to the next triennial for the Southwest region due in December 2021, or how the indicative screens can be modified to reflect the Resource Adequacy reserve margin obligations and capacity procurement in CAISO.^[62] We note that relief from the requirement to submit screens may be extended to capacity sellers in CAISO in the future, if CAISO develops an ISO-administered capacity market that is subject to Commission-approved market monitoring and mitigation.

2. SPP

a. Comments

43. Certain commenters request extending the proposal to grant relief from submitting the indicative screens to capacity sellers in the SPP market.^[63]

44. Evergy/Xcel assert that SPP's lack of an RTO-administered capacity market does not mean that capacity sellers in SPP can exercise market power. Evergy/Xcel state that other safeguards exist in SPP, such as transparent energy pricing, comprehensive must-offer requirements, vigorous independent market monitoring, and Commission-accepted mitigation measures.^[64] Evergy/Xcel also point to other safeguards, such as state regulators' oversight and review of capacity sales in retail rate cases, the Commission's authority to require the submission of indicative screens, the continued submission of EQRs, and the continued ability to file complaints under FPA section 206.^[65]

45. Evergy/Xcel state that the Commission rejected proposed mitigation in MISO, finding that the Minimum Offer Price Rule that would mitigate against the potential exercise of market power by buyers of capacity was unnecessary because of the predominance of vertically-integrated utilities and bilateral contracting and minimal use of the voluntary MISO capacity market. Evergy/Xcel maintain that these same factors apply to SPP, as it “mostly consists of vertically-integrated utilities with a small number of independent generators.” According to Evergy/Xcel, while “`most' capacity is transacted bilaterally or self-supplied in MISO, all capacity in SPP is transacted bilaterally or self-supplied. Thus `most' capacity transactions in MISO are not subject to direct monitoring or mitigation, just as in SPP.” ^[66]

b. Commission Determination

46. We adopt the NOPR proposals to require capacity sellers in SPP to continue to submit indicative screens and to eliminate the rebuttable presumption that Commission-approved RTO/ISO market monitoring and mitigation is sufficient to address any horizontal market power concerns regarding sales of capacity in SPP.

47. We disagree with Evergy/Xcel that certain safeguards present in SPP justify removal of the requirement to submit screens for capacity sales. While these safeguards are important, they do not fully allay the concerns about the lack of an RTO-administered capacity market with Commission-approved monitoring and mitigation. For example, the must-offer requirement as a safeguard is not relevant here because it applies to energy sales, not capacity sales. Furthermore, as discussed in the NOPR, while we acknowledge state review ^[67] of SPP capacity sales, we conclude that it is not sufficient oversight to extend relief to capacity sellers that would otherwise study the SPP market. As we found above with respect to CAISO, there is no transparent market price determined under Commission-approved rules for capacity in SPP comparable to the market price for capacity established by RTOs/ISOs with centralized capacity markets.

48. We acknowledge that SPP is similar to MISO in that it mostly consists of vertically-integrated utilities with a small number of independent generators. However, MISO conducts annual capacity auctions subject to Commission-approved monitoring and mitigation, thereby disciplining the price of bilateral capacity sales and providing capacity buyers with protections that are not available in SPP. The SPP market lacks a transparent market price for capacity and SPP does not review or mitigate capacity prices.

C. Clarifications for Capacity Sellers in CAISO and SPP

a. Comments

49. Calpine asks that the Commission make the following clarification in Paragraph 51 of the NOPR “that, in the event of indicative screen failures, the CAISO (or SPP) Seller's evidentiary burden is limited to demonstrating that it lacks market power in capacity markets, or to propose satisfactory mitigation for capacity sales, but that the CAISO (or SPP) Seller may still rely on a rebuttable presumption that it lacks market power in energy and ancillary services markets as a result of Commission-approved market monitoring and mitigation provisions in the CAISO (or SPP) Tariff.” ^[68]

50. Powerex states that the NOPR introduces an ambiguity about which markets a Seller would be required to evaluate for purposes of making capacity sales. Specifically, Paragraph 49 of the NOPR states that the Commission proposes “to require any Seller seeking to sell capacity at the market-based rates in CAISO or SPP, either as a bundled or unbundled product or on a short-term or long-term basis, to submit the indicative screens.” ^[69] Powerex asserts that “[r]ead literally, the foregoing statement would require all [market-based rate] sellers wishing to sell capacity in CAISO or SPP to study these markets as a relevant market and to submit the indicative screens, even though many [market-based rate] sellers making sales in CAISO and SPP do not presently submit indicative screens for those markets because they do not own or control generation in those markets and because those markets are not first-tier markets.” As such, Powerex believes Paragraph 49's “expansive language requiring `any seller' seeking to sell capacity in CAISO or SPP to submit indicative screens is ambiguous and potentially over-broad.” ^[70]

b. Commission Determination

51. We agree with Calpine that the addition of “capacity” appropriately clarifies Paragraph 51 of the NOPR. Therefore, we clarify that in the event of indicative screen failures, the CAISO (or SPP) Seller's evidentiary burden is limited to demonstrating that it lacks market power in capacity markets, or to proposing a satisfactory mitigation plan that is specific to capacity sales. Additionally, we note that the CAISO (or SPP) Seller may still rely on the rebuttable presumption that it lacks market power in energy and ancillary services markets as a result of Commission-approved market monitoring and mitigation.

52. We agree with Powerex that Paragraph 49's language requiring “any seller” seeking to sell capacity in CAISO or SPP to submit indicative screens is unclear. We clarify that the proposal adopted in the final rule requires that any RTO/ISO seller that would normally study CAISO or SPP as a relevant market, and that seeks to offer capacity at market-based rates in those markets, either as a bundled or unbundled product or on a short-term or long-term basis, must submit the indicative screens to demonstrate that it will not have market power in capacity sales.

D. Retention of Screens for EIM

1. Comments

53. While the Commission did not include in its proposal any changes for Sellers that study the Western Energy Imbalance Market (EIM), CAISO DMM and EIM Entities submitted comments in which they seek clarification that the proposal will apply to participants in the EIM and advocate for this result.^[71] Specifically, EIM Entities argue that because the EIM is part of CAISO's real-time energy market and is subject to Commission-approved market monitoring and mitigation, indicative screens should not be required for purposes of obtaining or retaining market-based rate authority in the EIM.^[72]

54. EIM Entities state that the EIM has become an increasingly liquid market that offers competitive supply from a significant number of participants. They argue that the EIM is structurally competitive, asserting that “[t]he DMM has presented analysis and the Commission has affirmed in multiple EIM orders that the EIM is structurally competitive due to absence of pivotal suppliers and low frequency of price separation,” and in those intervals where potential structural market power could exist, it would be mitigated by CAISO's real-time bid mitigation procedures.^[73] EIM Entities also argue that the requirement to perform indicative screens, as well as congestion and price separation analysis, on five-minute dispatch intervals in the EIM is “complex and financially burdensome to EIM entities.” ^[74] Finally, EIM Entities note that CAISO has implemented improvements to the accuracy of its mitigation regime that serve to reduce instances of either over or under-mitigation.^[75]

55. CAISO DMM states that, unlike the local market power mitigation procedures applied within the CAISO, the automated market power mitigation procedures applied to each EIM balancing authority area provide effective market power mitigation on a system-wide level across each individual EIM balancing area.^[76] Therefore, CAISO DMM believes that the EIM should be treated as an energy market that is subject to Commission-approved market monitoring and mitigation.

2. Commission Determination

56. We will not extend the relief proposed in the NOPR to Sellers in the EIM at this time. While the Commission has accepted the use of CAISO's real-time local market power mitigation process in the EIM,^[77] the Commission has not held that market monitoring and mitigation in the EIM is sufficient to address market power concerns, and the NOPR did not propose to expand the relief from the requirement to submit screens in the EIM or seek comment on the sufficiency of the mitigation.

E. Bilateral Sales

1. Comments

57. Several commenters assert that monitoring and mitigation does not ensure just and reasonable rates for bilateral sales of electricity in RTO/ISO markets.^[78] AAI/APPA/NRECA argue that “[t]he NOPR provides no factual or legal support for its claims that private monitoring and mitigation of RTO/ISO markets will indirectly ensure just and reasonable rates in non-RTO/ISO markets” and “no prior Commission order or court decision supports this proposition.” ^[79] AAI/APPA/NRECA argue that the NOPR's claim that RTO/ISO markets will discipline market power in long-term bilateral markets is “unsubstantiated and illogical.” ^[80] AAI/APPA/NRECA state that purchases from RTO/ISO-run capacity auctions are not a substitute for self-supply arrangements and long-term bilateral capacity purchases needed by a load-serving entity seeking to provide rate stability for its retail customers.^[81]

58. TAPS asserts that there is no basis for assuming that voluntary RTO/ISO capacity markets are substitutes for bilateral transactions, especially for load-serving entities that rely heavily on bilateral transactions to meet their resource requirements.^[82] According to TAPS, spot markets and one-year capacity products do not provide a sufficient benchmark against which to compare prices in bilateral markets, given the non-substitutable nature of these products.^[83] TAPS asserts that the one-year product sold on mandatory capacity markets is not an adequate substitute for long-term bilateral contracts and the NOPR makes no claims to the contrary.^[84] According to TAPS, just as a night at an Airbnb is not a substitute for the purchase of a home, the price of a night at an Airbnb does not provide a benchmark against which to compare the price of purchasing a home.^[85] TAPS also criticizes the NOPR's finding that bilateral markets for energy and capacity should be competitive so long as RTO/ISO energy and capacity markets are competitive, and monitoring and mitigation sufficiently protects against the exercise of market power in these markets. TAPS argues that the Commission makes no showing that RTO/ISO energy and capacity markets are competitive.^[86] TAPS argues that even if one were to credit the NOPR's contention that competitive auction prices discipline bilateral sales (to some unspecified degree), this reasoning runs “directly afoul” of the court precedent stating that the Commission cannot rely upon market forces as a basis for approving market-based rate transactions.^[87]

2. Commission Determination

59. We find that Commission-approved RTO/ISO monitoring and mitigation will enable the Commission to retain sufficient oversight of bilateral sales in RTO/ISO markets. We disagree with AAI/APPA/NRECA and TAPS's suggestion that the Commission's statement that RTO/ISO mitigation can effectively discipline bilateral transactions is “unsubstantiated.” In the NOPR, the Commission acknowledged that purchases in short-term RTO/ISO energy and capacity markets are not necessarily perfect substitutes for long-term bilateral purchases of energy and/or capacity. However, AAI/APPA/NRECA and TAPS make an unsupported logical leap in suggesting that these products are not substitutable at all, and therefore prices in the RTO/ISO-administered energy and capacity markets do not discipline or provide a useful benchmark against which to compare prices offered in bilateral markets within RTOs/ISOs. These products may be imperfect substitutes but that does not mean that there is no relationship between prices in RTO/ISO-administered markets and bilateral markets. As the Commission found in Order No. 697-A, “[i]n RTO/ISOs, buyers have access to centralized, bid-based short-term markets which will discipline a seller's attempt to exercise market power in long-term contracts because the would-be buyer can always purchase from the short-term market if a seller tries to charge an excessive price.” ^[88]

60. RTO/ISO-administered capacity auctions establish prices for prospective deliveries of capacity—the firm supply needed by load-serving entities. PJM's capacity auctions, for example, establish prices for capacity to be delivered in three years. We find that such prices, along with RTO/ISO-administered energy prices and other liquid and frequently traded products, such as standardized forward contracts, provide a benchmark against which to compare prices offered in the market for long-term bilateral contracts.^[89]

61. We also note that the Commission has consistently found that long-term markets for energy and capacity are competitive in the absence of barriers to entry.^[90] TAPS does not provide any evidence that RTO/ISO markets suffer from barriers to entry.

62. Contrary to TAPS's contention, eliminating the requirement for Sellers to submit screens in certain RTOs/ISOs is not inconsistent with Lockyer because the Commission is not “relying on market forces alone” to ensure that these bilateral sales result in just and reasonable rates. In addition to RTO/ISO mitigation measures, RTO/ISO sellers engaged in these bilateral sales remain subject to EQR reporting requirements, which comprise part of the post-approval reporting requirements that reassured the court that the Commission was not relying on market forces alone.^[91] As the U.S. Court of Appeals for the Ninth Circuit recognized, the Commission conducts ongoing analysis of ex post transactional EQR and other market data to detect indications of market power in the wholesale electricity markets “to determine whether rates were `just and reasonable' and whether market forces were truly determining the price.” ^[92] Additionally, as is currently the case, in the event someone is aware of a situation where a Seller is exercising market power in a bilateral transaction in an RTO/ISO geographic area, evidence of that exercise of market power, for example an analysis of EQR data, could serve as the basis of a complaint or a protest. The Commission is not aware of any such challenges since the issuance of Order No. 697.

F. Current Status and Effectiveness of RTO/ISO Monitoring and Mitigation

1. Comments

63. ELCON tentatively supports the proposal in the NOPR but questions the effectiveness of RTO/ISO monitoring and mitigation and suggests that the Commission could do more to elucidate the impact of horizontal market power on price formation in the RTOs/ISOs. Specifically, ELCON conditionally supports the NOPR, but only if the Commission explicitly and fully retains its authority to take direct action to prevent potential exercise of horizontal market power and simultaneously initiates a review of the effectiveness of RTO/ISO market monitoring and mitigation practices when issuing the final rule.^[93] ELCON argues that ultimately it would be more productive if, instead of focusing on the indicative screens, Commission staff resources were redirected toward robust examination of dynamic horizontal market power, monitoring, and mitigation in the RTOs/ISOs.^[94] ELCON states that the Commission should bolster RTO/ISO and Commission reporting to provide more transparency and analytic insights on the influence of horizontal market power in price formation, which includes more refined markup estimates and the aggregate and localized cost to load effects.^[95] ELCON suggests that the Commission could initiate this process with a notice of inquiry and technical conference, before proceeding to the RTO/ISO specific determinations that would be necessary to achieve such action.^[96]

64. In contrast, Competitive Suppliers urge the Commission to avoid holding market power mitigation to an “unreasonable standard,” noting that existing market power mitigation protocols are better suited to prevent the exercise of market power than static indicative screens and that market power mitigation protocols will necessarily evolve with experience and changes in market fundamentals. Competitive Suppliers argue that the Commission should not delay implementing its proposal to relieve Sellers of the burden to file indicative screens while it waits for the mitigation protocols to cross the “elusive finish line represented by the standard that market power mitigation is ‘complete.' ” ^[97]

2. Commission Determination

65. We disagree with ELCON that it is necessary to initiate a formal review of the effectiveness of RTO/ISO monitoring and mitigation practices concurrent with this final rule. The Commission has previously accepted each RTO/ISO's market monitoring and mitigation provisions as just and reasonable. Moreover, as discussed in the NOPR, market power mitigation in RTOs/ISOs uses more granular data than the indicative screens.^[98] The indicative screens use static data from a historical study year to evaluate a Seller's ability to exercise market power in the relevant market (i.e., at the balancing authority area/market, or submarket, level). In contrast, RTO/ISO mitigation uses interval-specific market and operational data to identify, in real-time, binding transmission constraints that create conditions that could result in the emergence of local market power. Removing the indicative screens does not affect the RTOs/ISOs' application of the market power monitoring and mitigation provisions in their markets.

66. Moreover, nothing in this final rule precludes an RTO/ISO from filing to amend the existing market power mitigation provisions if improvement is needed. Indeed, in recent years, improvements have been made to market monitoring and mitigation protocols in all RTO/ISO markets.^[99] The Commission will continue to scrutinize RTO/ISO market monitoring and mitigation provisions and take necessary action, as appropriate, should any issues arise.

G. Other Issues Raised By Commenters

1. Change in Status and Triennial Updates

a. Comments

67. EEI requests that the Commission eliminate the requirement for change in status reporting and reconsider the continued need for the triennial market power update for all Sellers relying on Commission-approved market monitoring and mitigation.^[100] EEI asks the Commission to clarify the characteristics it relies upon in granting market-based rate authority. To the extent information is not relied upon by the Commission in its initial grant of market-based rate authorization, EEI contends that it also is not relevant to changes in status and Sellers should not be required to submit it.^[101]

68. EEI points to how the Commission currently requires that change in status reporting and triennial market power updates include information on any new affiliations with entities that own, operate, or control transmission facilities. EEI argues that “[s]o long as the affiliated transmission facilities are turned over to the operational control of an RTO/ISO, subject to an Open Access Transmission Tariff (OATT) or have received a waiver of the OATT requirement, [market-based rate] sellers should not be required to report such information as changes in status.” ^[102] EEI adds that the same principles justify eliminating reporting of inputs to power production. According to EEI, “[s]uch inputs would comprise part of the price that is controlled by the Commission-approved market monitoring and mitigation, thereby addressing any market power concerns.” ^[103]

69. Similarly, SoCal Edison argues that RTO/ISO sellers who are exempt from submitting screens under the proposal should also be relieved of the requirement to file a change in status for any net increases of generation in their portfolios. In SoCal Edison's view, an increase in generation would not affect the characteristics the Commission relied upon in granting the Seller market-based rate authority because, under the proposal, the Commission is no longer relying on any particular amount of generating capacity when granting market-based rate authority.^[104]

70. Contrary to these comments, AAI/APPA/NRECA urge the Commission to gather more information from Sellers and advocate for removing the current stay of the requirement in 18 CFR 35.37(a)(2) that Sellers submit an organizational chart. AAI/APPA/NRECA contend that the organizational chart requirement should be reinstituted regardless of whether the Commission adopts the NOPR, but particularly if the Commission eliminates the indicative screen requirement based in part on “the availability of other data regarding horizontal market power.” ^[105]

b. Commission Determination

71. We reject, as beyond the scope of this proceeding, EEI's and SoCal Edison's requests to eliminate the requirement for change in status reporting and to reconsider the continued need for the triennial market power updates. The Commission did not propose to eliminate or change the triennial or change in status requirements and did not request comment on such a proposal.

72. Similarly, we deny as beyond the scope of this proceeding, AAI/APPA/NRECA's request that the Commission remove the current stay of the requirement in 18 CFR 35.37(a)(2) that Sellers submit an organizational chart.^[106]

2. Rights of Market Monitors

a. Comments

73. Both OPSI and PJM IMM request that the Commission definitively state that independent market monitors have the right to file FPA section 206 complaints, including complaints against an RTO/ISO for the independent market monitor's relevant region. OPSI states that the right to file FPA section 206 complaints is needed “to ensure effective and comprehensive market power mitigation and public confidence in the markets.” ^[107] PJM IMM emphasizes that market monitors' ability to initiate an FPA section 206 proceeding when markets are not competitive is a critical part of the NOPR's reliance on effective market monitoring to support market‐based rates.^[108]

74. PJM IMM also asserts that adequate market power monitoring and mitigation “requires that market monitors have equal standing with the RTO and its membership to file tariff revisions to the market monitoring and mitigation sections of the tariff.” ^[109] PJM IMM suggests that the Commission could achieve equal standing by requiring that all filings to change monitoring and mitigation fall under FPA section 206, as opposed to the current practice of allowing RTOs/ISOs to file changes under FPA section 205. PJM IMM states that the FPA section 206 approach “would allow the Commission to choose the most effective monitoring and mitigation practices, ensuring that markets remain competitive and ensuring that market based rates are justified.” ^[110]

b. Commission Determination

75. We find that OPSI and the PJM IMM's request that the Commission definitively state that independent market monitors have the right to file FPA section 206 complaints is beyond the scope of this proceeding. The Commission did not make, or request comment on, such a proposal.

76. We similarly find PJM IMM's suggestion that all filings to change monitoring and mitigation fall under FPA section 206 to be beyond the scope of this rulemaking, as the Commission did not make, or request comment on, such a proposal.

3. Corporate Character Reporting

a. Comments

77. Public Citizen asserts that the Commission should establish corporate character reporting standards for market-based rate applications. Public Citizen states that under the Commission's current regulations, there is no requirement that an applicant disclose adjudications, criminal convictions, or adverse legal or regulatory rulings against it. Public Citizen maintains that the lack of corporate character reporting requirements “leaves the Commission vulnerable to approving market-based rate authority to an entity that may have a demonstrated track record of frequent and serious legal violations.” ^[111]

b. Commission Determination

78. We find that Public Citizen's request for establishing corporate character reporting requirements for market-based rate applications to be beyond the scope of this proceeding. The Commission did not propose to establish corporate character reporting requirements or request comment on such a proposal.

4. Data Collection NOPR and Market Power NOI

a. Comments

79. AAI/APPA/NRECA argue that the Commission should not act on this NOPR before it has acted on a related pending rulemaking in Docket No. RM16-17-000 (Data Collection NOPR) and a notice of inquiry in Docket No. RM16-21-000 (Market Power NOI). AAI/APPA/NRECA argue that the NOPR, if adopted, would reduce the information available to the Commission for assessing and monitoring the ability of Sellers to exercise market power at the same time the Commission is evaluating whether the Commission's existing market power information requirements and analyses are sufficient.^[112]

b. Commission Determination

80. We are not persuaded by, and therefore reject AAI/APPA/NRECA's assertion that the Commission should first act on the Data Collection NOPR and Market Power NOI proceedings before acting on the instant NOPR. We see no reason why the Commission must first act in those proceedings before taking action to remove the screen requirement as proposed in the NOPR. Any actions taken in the Data Collection NOPR and Market Power NOI will not impact the implementation of the removal of the screen requirement. As noted above, the Commission will continue to monitor RTO/ISO mitigation provisions on an ongoing basis and take necessary action, as appropriate. In addition, we note that a final rule in Docket No. RM16-17-000 is being issued concurrently with this final rule.^[113]

IV. Information Collection Statement

81. The Paperwork Reduction Act (PRA) ^[114] 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 ^[115] require approval of certain information collection requirements contained in final rules published in the Federal Register.^[116] Upon approval of a collection of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of an agency rule will not be penalized for failing to respond to the collection of information unless the collection of information display a valid OMB control number.

82. The final rule revises the requirements for Sellers seeking to obtain or retain market-based rate authority that study certain RTOs, ISOs, or submarkets therein, as discussed above. The Commission anticipates that the revisions, once effective, would reduce regulatory burdens.^[117] The Commission will submit the reporting requirements to OMB for its review and approval under section 3507(d) of the PRA.^[118]

83. While the Commission expects that the revisions adopted in this final rule will reduce the burdens on affected entities, the Commission nonetheless solicited public comments regarding the Commission's need for this information, whether the information will have practical utility, the accuracy of the burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected or retained, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques. Specifically, the Commission asked that any revised burden or cost estimates submitted by commenters be supported by sufficient detail to understand how the estimates are generated. The Commission did not receive any comments concerning its burden or cost estimates.

84. Section 35.37 of the Commission's regulations currently requires Sellers to submit a horizontal market power analysis when seeking to obtain or retain market-based rate authority.^[119] The final rule will implement a streamlined procedure that will eliminate the requirement for Sellers to file the indicative screens as part of a horizontal market power analysis for RTO/ISO markets with RTO/ISO-administered energy, ancillary services, and capacity markets subject to Commission-approved RTO/ISO monitoring and mitigation. In any RTO/ISO market that does not have an RTO/ISO-administered capacity market subject to Commission-approved RTO/ISO monitoring and mitigation, Sellers would continue to be required to submit indicative screens for authorization to make capacity sales. Eliminating the requirement to file indicative screens in certain markets will reduce the burden of filing a horizontal market power analysis for a large portion of Sellers when filing triennial updated market power analyses, initial applications for market-based rate authority, and notices of change in status.

85. Burden Estimate: The estimated burden and cost for the requirements are as follows.

Burden Reductions in Final Rule, RM19-2-000 ¹²⁰

Requirement	Number of respondents	Annual number of responses per respondent	Total number of responses	Average burden & cost per response	Total annual burden hours & cost	Annual cost per respondent ($)
	(1)	(2)	(1) * (2) = (3)	(4)	(3) * (4) = (5)	(5) ÷ (1)
Market Power Analysis in New Applications for Market-based Rates for RTO/ISO Sellers	72	1	72	−230 hrs. −$21,620	−16,560 hrs. −$1,556,640	−$21,620
Triennial Market Power Analysis Updates for RTO/ISO Sellers	33	1	33	−230 hrs. −$21,620	−7,590 hrs. −$713,460	−$21,620
Total			105		−24,150 hrs. −$2,270,100

86. After implementation of the proposed changes, the total estimated annual reduction in cost burden to respondents is $2,270,100 [24,150 hours * $94 = $2,270,100].^[121]

Title: FERC-919, Market Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities.

Action: Revision of Currently Approved Collection of Information.

OMB Control No.: 1902-0234.

Respondents: Public utilities, wholesale electricity sellers, businesses, or other for profit and/or nonprofit institutions.

Frequency of Responses:

Initial Applications: On occasion.

Updated Market Power Analyses: Updated market power analyses are filed every three years by Category 2 Sellers seeking to retain market-based rate authority.

Change in Status Reports: On occasion.

Necessity of the Information:

Initial Applications: In order to obtain market-based rate authority, the Commission must first evaluate whether a Seller has the ability to exercise market power. Initial applications help inform the Commission as to whether an entity seeking market-based rate authority lacks market power or has adequately mitigated any market power, and whether sales by that entity will be just and reasonable.

Updated Market Power Analyses: Triennial updated market power analyses allow the Commission to monitor market-based rate authority to detect changes in market power or potential abuses of market power. The updated market power analysis permits the Commission to determine that continued market-based rate authority will still yield rates that are just and reasonable.

Change in Status Reports: The change in status requirement permits the Commission to ensure that rates and terms of service offered by market-based rate Sellers remain just and reasonable.

Internal Review: The Commission has reviewed the reporting requirements and made a determination that revising the reporting requirements will ensure the Commission has the necessary data to carry out its statutory mandates, while eliminating unnecessary burden on industry. The Commission has assured itself, by means of its internal review, that there is specific, objective support for the burden estimate associated with the information requirements.

87. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: [e-mail], phone: [phone], fax: [phone]].

88. Comments concerning the collection of information and the associated burden estimates may also be sent to: Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. Due to security concerns, comments should be sent electronically to the following email address: [e-mail]. Comments submitted to OMB should refer to FERC-919 (OMB Control No. 1902-0234).

V. Environmental Analysis

89. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.^[122] The Commission has categorically excluded certain Docket Number RM19-2-000 actions from this requirement as not having a significant effect on the human environment.^[123] The actions proposed here fall within the categorical exclusions in the Commission's regulations for rules that are clarifying, corrective, or procedural, or do not substantially change the effect of legislation or regulations being amended.^[124] In addition, this final rule is categorically excluded as an electric rate filing submitted by a public utility under Federal Power Act sections 205 and 206.^[125] As explained above, this final rule, which addresses the issue of electric rate filings submitted by public utilities for market-based rate authority, is clarifying in nature. Accordingly, no environmental assessment is necessary and none has been prepared in this final rule.

VI. Regulatory Flexibility Act

90. The Regulatory Flexibility Act of 1980 (RFA) ^[126] generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. The RFA mandates consideration of regulatory alternatives that accomplish the stated objectives of a final rule and minimize any significant economic impact on a substantial number of small entities. In lieu of preparing a regulatory flexibility analysis, an agency may certify that a final rule will not have a significant economic impact on a substantial number of small entities.

91. The Small Business Administration's (SBA) Office of Size Standards develops the numerical definition of a small business.^[127] The SBA size standard for electric utilities is based on the number of employees, including affiliates.^[128] Under SBA's current size standards, an electric utility (one that falls under NAICS codes 221122 [electric power distribution], 221121 [electric bulk power transmission and control], or 221118 [other electric power generation]) ^[129] are small if it, including its affiliates, employs 1,000 or fewer people.^[130]

92. Out of the 2,500 market-based rate Sellers who are potential respondents subject to the requirements proposed by this final rule, the Commission estimates approximately 74 percent of the affected entities (or approximately 1,850) are small entities. We estimate that none of the 1,850 small entities to whom the final rule apply will incur additional cost because these small entities will no longer be required to file indicative screens causing a reduction in burden, not an increase.

93. The final rule will eliminate some requirements and reduce burden on entities of all sizes (public utilities seeking and currently possessing market-based rate authority). Implementation of the final rule is expected to reduce total annual burden by 24,150 hours per year or 9.66 hours per entity with a related reduced cost of $2,270,100 per year or $908.04 per entity to the industry when filing triennial market power analyses and market power analyses in new applications for market-based rates, and will further reduce burden when filing notices of change in status.

94. As discussed in Order No. 697,^[131] current regulations regarding market-based rate Sellers under Subpart H to Part 35 of Title 18 of the Code of Federal Regulations exempt many small entities from significant filing requirements by designating them as Category 1 Sellers. Category 1 Sellers are exempt from triennial updates and may use simplifying assumptions, such as Sellers with fully-committed generation may submit an explanation that their generation is fully committed in lieu of submitting indicative screens, that the Commission allows Sellers to utilize in submitting their horizontal market power analysis.

95. The final rule will relieve Sellers in certain RTO/ISO markets of the requirement to submit indicative screens and will reduce the burden on those Sellers, including small entities. The changes to the Commission's regulations are estimated to cause a reduction of 41 percent in total annual burden to Sellers when filing triennial market power analyses and market power analyses in new applications for market-based rates, including small entities.

96. Accordingly, pursuant to section 605(b) of the RFA, the Commission certifies that this final rule will not have a significant economic impact on a substantial number of small entities.

VII. Document Availability

97. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission's Home Page (http://www.ferc.gov) and in the Commission's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern Time) at 888 First Street NE, Room 2A, Washington, DC 20426.

98. From the Commission's Home Page on the internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

99. User assistance is available for eLibrary and the Commission's website during normal business hours from FERC Online Support at [phone] (Toll-free at 1-866-208-3676) or email at [e-mail], or the Public Reference Room at [phone], TTY [phone]. Email the Public Reference Room at [e-mail].

VIII. Effective Date and Congressional Notification

100. This final rule is effective September 24, 2019. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a major rule as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996.^[132] This rule is being submitted to the Senate, House, Government Accountability Office, and Small Business Administration.

List of Subjects in 18 CFR Part 35

• Electric power rates
• Electric utilities
• Reporting and recordkeeping requirements

By the Commission.

Kimberly D. Bose,

Secretary.

In consideration of the foregoing, the Commission proposes to amend part 35, chapter I, title 18, Code of Federal Regulations, as follows:

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

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

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

§ 35.37

[Amended]

2. Amend § 35.37 as follows:

a. Redesignate paragraph (c)(5) as (c)(7); and

b. Add new paragraph (c)(5) and paragraph (c)(6).

The additions read as follows:

§ 35.37

Market power analysis required.

* * * * *

(c) * * *

(5) In lieu of submitting the indicative market power screens, Sellers studying regional transmission organization (RTO) or independent system operator (ISO) markets that operate RTO/ISO-administered energy, ancillary services, and capacity markets may state that they are relying on Commission-approved market monitoring and mitigation to address potential horizontal market power Sellers may have in those markets.

(6) In lieu of submitting the indicative market power screens, Sellers studying RTO or ISO markets that operate RTO/ISO-administered energy and ancillary services markets, but not capacity markets, may state that they are relying on Commission-approved market monitoring and mitigation to address potential horizontal market power that Sellers may have in energy and ancillary services. However, Sellers studying such RTOs/ISOs would need to submit indicative market power screens if they wish to obtain market-based rate authority for wholesale sales of capacity in these markets.

* * * * *

Note:

The following appendix will not be published in the Code of Federal Regulations.

Appendix A

List of Commenters and Acronyms

Commenter	Short name/acronym
American Antitrust Institute, American Public Power Association, and National Rural Electric Cooperative Association	AAI/APPA/NRECA.
California Independent System Operator—Department of Market Monitoring	CAISO DMM.
Calpine Corporation	Calpine.
EDF Renewables, Inc	EDF Renewables.
Edison Electric Institute	EEI.
EIM Entities (Arizona Public Service Company, Avista Corporation, Idaho Power Company, NV Energy, Inc., PacifiCorp, and Portland General Electric Company)	EIM Entities.
Electric Power Supply Association and Independent Energy Producers Association	Competitive Suppliers.
Electricity Consumers Resource Council	ELCON.
Evergy Companies (Westar Energy, Inc., Kansas City Power & Light Company, and KCP&L Greater Missouri Operations Company) and Xcel Energy Services Inc	Evergy/Xcel.
FirstEnergy Service Company	FirstEnergy.
Indicated Generation Investors (Southwest Generation Operating Company, LLC, Ares EIF Management, LLC, Northern Star Generation Services Company LLC, Astoria Energy LLC and Astoria Energy II LLC, and Coronal Management, LLC)	Indicated Generation Investors.
Monitoring Analytics, LLC	PJM IMM.
Organization of PJM States, Inc	OPSI.
Pacific Gas and Electric Company	PG&E.
Powerex Corp	Powerex.
Public Citizen	Public Citizen.
Southern California Edison Company	SoCal Edison.
Transmission Access Policy Study Group	TAPS.

Footnotes

1.  Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets, 165 FERC ¶ 61,268 (2018) (NOPR).

2.  The term “Seller” is defined as any person that has authorization to or seeks authorization to engage in sales for resale of electric energy, capacity or ancillary services at market-based rates. 18 CFR 35.36(a)(1).

3.  The term “RTO/ISO markets” in this final rule includes any submarkets therein.

4.  At this time, California Independent System Operator Corporation (CAISO) and Southwest Power Pool, Inc. (SPP) do not have Commission-approved RTO/ISO capacity markets that include Commission-approved market monitoring and mitigation.

5.  Although the Commission did not request reply comments, several commenters nonetheless submitted reply comments. The Commission rejects such reply comments.

6.  Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, 119 FERC ¶ 61,295, at PP 62, 399, 408, 440, clarified, 121 FERC ¶ 61,260 (2007), order on reh'g, Order No. 697-A, 123 FERC ¶ 61,055, clarified, 124 FERC ¶ 61,055, order on reh'g, Order No. 697-B, 125 FERC ¶ 61,326 (2008), order on reh'g, Order No. 697-C, 127 FERC ¶ 61,284 (2009), order on reh'g, Order No. 697-D, 130 FERC ¶ 61,206 (2010), aff'd sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011), cert. denied, sub nom. Public Citizen, Inc. v. FERC, 567 U.S. 934 (2012).

7.  Category 1 Seller means a Seller that: (1) Is either a wholesale power marketer or wholesale power producer that owns, controls or is affiliated with 500 MW or less of generation in aggregate per region; (2) does not own, operate, or control transmission facilities other than limited equipment necessary to connect individual generation facilities to the transmission grid (or has been granted waiver of the requirements of Order No. 888); (3) is not affiliated with anyone that owns, operates, or controls transmission facilities in the same region as the Seller's generation assets; (4) is not affiliated with a franchised public utility in the same region as the Seller's generation assets; and (5) does not raise other vertical market power issues. Sellers that are not Category 1 are designated as Category 2 Sellers and are required to file updated market power analyses. 18 CFR 35.36(a)(2).

8.  Order No. 697, 119 FERC ¶ 61,295 at P 62.

9.  Id. PP 33, 62-63.

10.  Where the Commission has made a specific finding that there is a submarket within an RTO/ISO, that submarket becomes a default relevant geographic market for Sellers located within the submarket for purposes of the horizontal market power analysis. See id. PP 15, 231.

11.  Order No. 697-A, 123 FERC ¶ 61,055 at P 111.

12.  Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 816, 153 FERC ¶ 61,065 (2015), order on reh'g Order No. 816-A, 155 FERC ¶ 61,188 (2016).

13.  Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 147 FERC ¶ 61,232, at P 10 (2014) (Order No. 816 NOPR).

14.  See id. PP 35-36.

15.  RTO/ISO sellers are Sellers that have an RTO/ISO market as a relevant geographic market.

16.  Order No. 816 NOPR, 147 FERC ¶ 61,232 at P 36.

17.  Order No. 816, 153 FERC ¶ 61,065 at P 27.

18.  NOPR, 165 FERC ¶ 61,268 at PP 61-70.

19.  TAPS at 20-21; AAI/APPA/NRECA at 29.

20.  AAI/APPA/NRECA at 15 (citing Order No. 697-A, 123 FERC ¶ 61,055 at P 109); TAPS at 7 (citing same).

21.  AAI/APPA/NRECA at 7; TAPS at 5 (quoting Cal. ex rel. Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004) (Lockyer).

22.  TAPS at 5 (citing Mont. Consumer Counsel v. FERC, 659 F.3d 910, 917 (9th Cir. 2011) (Mont. Consumer Counsel).

23.  AAI/APPA/NRECA at 7 (citing Blumenthal v. FERC, 552 F.3d 875, 882 (D.C. Cir. 2009) (Blumenthal).

24.  TAPS at 13.

25.  AAI/APPA/NRECA at 17.

26.  Id. at 26.

27.  TAPS at 22.

28.  Id. at 8.

29.  16 U.S.C. 824d.

30.  Public Citizen at 3.

31.  AAI/APPA/NRECA at 16.

32.  TAPS at 13.

33.  AAI/APPA/NRECA at 28.

34.  New Jersey Bd. of Pub. Utils. v. FERC, 744 F.3d 74, 100 (3rd Cir. 2014) (noting that “[c]ourts have repeatedly held that an agency may alter its policies despite the absence of a change in circumstances.” (citing Motor Vehicle Mfrs. Ass'n of United States, Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 57 (1983)); Tennessee Gas Pipeline Co., 105 FERC ¶ 61,120, at P 35 (2003) (the Commission's prior acceptance of tariff provisions does not preclude the Commission from reconsidering its policies), aff'd Tennessee Gas Pipeline Co. v. FERC, 400 F.3d 23 (D.C. Cir. 2005).

35.  See Lockyer, 383 F.3d at 1013; Blumenthal, 552 F.3d at 882; Mont. Consumer Counsel, 659 F.3d at 916.

36.  Only Category 2 Sellers are required to submit triennial updated market power analyses. 18 CFR 35.37(a)(1). Category 2 Sellers likely will have more of a presence in the market than Category 1 Sellers and are considered more likely to either fail one or more of the indicative screens or pass by a smaller margin than those that will qualify as Category 1 Sellers, or may present circumstances that could pose vertical market power issues. Order No. 697, 119 FERC ¶ 61,295 at P 852; 18 CFR 35.36(a)(2), (a)(3).

37.  Public Citizen at 3.

38.  16 U.S.C. 824e.

39.  PJM IMM at 4-5.

40.  See, e.g., Nevada Power Co., 155 FERC ¶ 61,249 (2016); FortisUS Energy Corp., 150 FERC ¶ 61,153 (2015); Alabama Power Co., 151 FERC ¶ 61,071 (2015); Duke Power, 109 FERC ¶ 61,270 (2004).

41.  Enhancement of Electricity Market Surveillance and Analysis through Ongoing Electronic Delivery of Data from Regional Transmission Organizations and Independent System Operators, Order No. 760, 139 FERC ¶ 61,053 (2012).

42.  Order No. 697-A, 123 FERC ¶ 61,055 at P 5.

43.  Public Citizen at 4-5 (also noting that the market monitors do not have corporate control protections to safeguard the public interest).

44.  AAI/APPA/NRECA at 19 (citing Old Dominion Elec. Coop. v. FERC, 892 F.3d 1223, 1234 (D.C. Cir. 2018)).

45.  Id. at 19-20 (citing Exelon Corp. v. FERC, 911 F.3d 1236 (D.C. Cir. 2018) (Exelon)).

46.  ISO New England Inc., 166 FERC ¶ 61,060, at P 8 (2019).

47.  Calpine at 4-5 (identifying structural safeguards in California that protect against the exercise of horizontal market power in the sale of capacity); EEI at 5-6 (mitigation methods exist in CAISO's Capacity Procurement Mechanism which address market power in the capacity sales); Indicated Generation Investors at 9-10 (“There is no credible case to be made that the presence or absence of a particular type of forward capacity market itself defines whether exercises of market power are prevented.”); PG&E at 3-4; Competitive Suppliers at 5-7; SoCal Edison at 3-6 (CAISO's Resource Adequacy framework provides similar monitoring and mitigation measures found in centralized capacity markets).

48.  Calpine at 7.

49.  Competitive Suppliers at 6.

50.  Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Order No. 784, 144 FERC ¶ 61,056 (2013), order on clarification, Order No. 784-A, 146 FERC ¶ 61,114 (2014).

51.  SoCal Edison at 4.

52.  Id. at 5.

53.  Id. at 7.

54.  CAISO DMM at 10-11; TAPS at 19-20 (noting that the indicative screens are especially important for capacity sales in RTOs that do not administer a capacity market); see also ELCON at 7-8 (“capacity markets present a fundamental challenge to horizontal market power detection and mitigation”).

55.  CAISO DMM at 10.

56.  Id. at 11.

57.  TAPS at 19-20.

58.  Id.

59.  Capacity sales in CAISO are reported in EQRs but that data, on its own, does not provide a meaningful market price given the different vintage, length, product characteristics, and terms and conditions of the contracts under which capacity is sold in CAISO.

60.  Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Order No. 784, 144 FERC ¶ 61,056, at P 95 (2013), order on clarification, Order No. 784-A 146 FERC ¶ 61,114 (2014).

61.  Boston Edison Co. Re: Edgar Electric Energy Company, 55 FERC ¶ 61,382 (1991); Allegheny Energy Supply Company, LLC, 108 FERC ¶ 61,082 (2004) (Edgar-Allegheny).

62.  SoCal Edison at 7.

63.  Evergy/Xcel at 7-12; EEI at 5-6. Indicated Generation Investors do not specifically reference SPP in their comments but state (at 8-9) that markets “in addition to the named Northeastern market” should be included in the relief that the NOPR proposes.

64.  Evergy/Xcel at 8.

65.  Id. at 9-10.

66.  Id. at 11-12.

67.  In the SPP region, capacity costs are recovered in the rate bases of franchised public utilities and, therefore, are subject to state regulatory review.

68.  Calpine at 9 (emphasis in original).

69.  NOPR, 165 FERC ¶ 61,268 at P 49.

70.  Powerex at 5.

71.  EIM Entities at 1; CAISO DMM at 8; see also EEI at 2 (requesting extension of relief to Sellers in the EIM).

72.  EIM Entities at 7.

73.  Id. at 7-8.

74.  Id. at 10.

75.  Id. at 12-13.

76.  CAISO DMM at 8-9.

77.  See Cal. Indep. Sys. Operator Corp., 147 FERC ¶ 61,231, order on reh'g, clarification, and compliance, 149 FERC ¶ 61,058 (2014).

78.  APPA/AAI/NRECA at 23; TAPS at 19.

79.  AAI/APPA/NRECA at 24.

80.  Id. at 25.

81.  Id.

82.  TAPS at 15-16.

83.  Id.

84.  Id. at 16.

85.  Id.

86.  Id.

87.  Id. at 18 (citing Lockyer, 383 F.3d at 1013).

88.  Order No. 697-A, 123 FERC ¶ 61,055 at P 285.

89.  RTOs/ISOs periodically calculate the cost of new entry or “CONE” to provide a benchmark price for new capacity. CONE is a measure of the revenue needed to recover the cost of a new generating unit, typically a gas-fired combustion turbine or combined cycle unit, net of energy revenues. While this is an administratively determined cost, it provides another useful benchmark that buyers can use to assess prices offered in the long-term bilateral market.

90.  Order No. 697, 119 FERC ¶ 61,295 at P 114; see also Order No. 697-A, 123 FERC ¶ 61,055 at P 279; Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996) (cross-referenced at 77 FERC ¶ 61,080), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002); Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 118 FERC ¶ 61,119, order on reh'g, Order No. 890-A, 121 FERC ¶ 61,297 (2007), order on reh'g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

91.  See Lockyer, 383 F.3d at 1014.

92.  Id.

93.  ELCON at 3.

94.  Id. at 10.

95.  Id.

96.  Id.

97.  Competitive Suppliers at 3-4.

98.  NOPR, 165 FERC ¶ 61,269 at P 28.

99.  See, e.g., Cal. Indep. Sys. Operator Corp., 157 FERC ¶ 61,091 (2016) (adding a new mitigation run for each five-minute real-time dispatch interval to address the potential for under-mitigation); Cal. Indep. Sys. Operator Corp., 143 FERC ¶ 61,078 (2013) (replacing a static competitive path assessment with a dynamic competitive path assessment in the hour-ahead scheduling process and the real-time market to better evaluate whether transmission constraints are competitive); Midcontinent Indep. Sys. Operator, Inc., 161 FERC ¶ 61,268 (2017) (establishing Dynamic Narrow Constrained Areas); ISO New England, Inc., 155 FERC ¶ 61,029 (2016) (addressing the potential exercise of market power associated with the retirement of existing resources); PJM Interconnection, L.L.C., 158 FERC ¶ 61,133 (2017) (revising the market power mitigation methodology for resources committed in the day-ahead market to update their offers in real-time, for the purposes of mitigation, electing to use the offer that results in the lowest cost to the PJM system); PJM Interconnection, L.L.C., Docket No. ER18-252-000 (Dec. 18, 2017) (delegated order) (applying market power tests to resources that are committed out-of-market and to resources that self-schedule in real-time); Sw. Power Pool, Inc., 165 FERC ¶ 61,242 (2018) (streamlining the process by which Frequently Constrained Areas are designated); N.Y. Indep. Sys. Operator, Inc., Docket No. ER18-1168-000 (May 14, 2018) (delegated order) (revising the market power mitigation provisions to address cases where Sellers submit inaccurate fuel type or fuel price information in fuel cost adjustments).

100.  EEI at 8-9.

101.  Id. at 9.

102.  Id. at 10-11.

103.  Id. at 11.

104.  SoCal Edison at 9-10.

105.  AAI/APPA/NRECA at 18 (citing NOPR, 165 FERC ¶ 61,268 at P 27).

106.  We note that the Commission is concurrently issuing a final rule in Docket No. RM16-17-000 that eliminates the requirement that Sellers submit an organizational chart. Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, Order No. 860, 168 FERC ¶ 61,039 (2019).

107.  OPSI at 4-5.

108.  PJM IMM at 7.

109.  Id. at 6.

110.  Id.

111.  Public Citizen Comments at 5.

112.  AAI/APPA/NRECA Comments at 30.

113.  Order No. 860, 168 FERC ¶ 61,039.

114.  44 U.S.C. 3507(d).

115.  5 CFR 1320.

116.  See 5 CFR 1320.12.

117.  “Burden” is the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. For further explanation of what is included in the information collection burden, refer to 5 CFR 1320.3.

118.  44 U.S.C. 3507(d).

119.  18 CFR 35.37.

120.  Although some Sellers may include the indicative screens when submitting a change in status filing, this is not required by the Commission's regulations. Thus, we estimate that the change in burden for change in status filings is de minimis. See 18 CFR 35.42.

121.  The estimated hourly cost (salary plus benefits) provided in this section are based on the figures for May 2018 posted by the Bureau of Labor Statistics for the Utilities sector (available at http://www.bls.gov/​oes/​current/​naics2_​22.htm) and updated March 2019 for benefits information (at http://www.bls.gov/​news.release/​ecec.nr0.htm). The hourly estimates for salary plus benefits are:

Economist: $70.83/hour

Electrical Engineer: $68.17/hour

Lawyer: $142.86/hour

The average hourly cost of the three categories is $93.95 [($70.83+$68.17+$142.86)/3]. The Commission rounds it up to $94.00/hour.

122.  Regulations Implementing the National Environmental Policy Act of 1969, Order No. 486, FERC Stats. & Regs., ¶ 30,783 (1987) (cross-referenced at 41 FERC ¶ 61,284).

123.  18 CFR 380.4.

124.  18 CFR 380.4(a)(2)(ii).

125.  18 CFR 380.4(a)(15).

126.  5 U.S.C. 601-612.

127.  13 CFR 121.101.

128.  Id. 121.201.

129.  The North American Industry Classification System (NAICS) is an industry classification system that Federal statistical agencies use to categorize businesses for the purpose of collecting, analyzing, and publishing statistical data related to the U.S. economy. United States Census Bureau, North American Industry Classification System, https://www.census.gov/​eos/​www/​naics/​.

130.  13 CFR 121.201 (Sector 22—Utilities).

131.  Order No. 697, 119 FERC ¶ 61,295 at PP 1126-1129.

132.  5 U.S.C. 804(2).