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Proposed Rule

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

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Start Preamble

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Notice of proposed rulemaking.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is proposing to revise 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 proposed modification of the Commission's horizontal market power analysis would relieve such sellers of the obligation to submit indicative screens when seeking to obtain or retain market-based rate authority. The Commission's regulations would 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 lacking an RTO/ISO-administered capacity market, we propose that Commission-approved RTO/ISO monitoring and mitigation no longer be presumed sufficient to address any horizontal market power concerns for capacity sales where there are indicative screen failures.

DATES:

Comments are due March 18, 2019.

ADDRESSES:

Comments, identified by docket number, may be filed electronically at http://www.ferc.gov in acceptable native applications and print-to-PDF, but not in scanned or picture format. For those unable to file electronically, comments may be filed by mail or hand-delivery to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426. The Comment Procedures Section of this document contains more detailed filing procedures.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Gregory Basheda, Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-6479, Gregory.basheda@ferc.gov.

Laura Chipkin, Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-8615, Laura.chipkin@ferc.gov.

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SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.
I. Introduction1
II. Background3
A. The Market-Based Rate Program3
B. Order No. 816 Proposal7
C. Comments on Order No. 816 Proposal10
III. Discussion23
A. Overview of Existing RTO/ISO Market Power Monitoring and Mitigation26
B. Proposal Implementation42
C. Bilateral Transactions56
D. The Commission Will Continue To Ensure That Market-Based Rates Are Just and Reasonable61
IV. Information Collection Statement71
V. Environmental Analysis77
VI. Regulatory Flexibility Act78
VII. Comment Procedures84
VIII. Document Availability88

I. Introduction

1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) seeks comment on a proposal to modify the horizontal market power analysis for certain Regional Transmission Organization (RTO) and Independent System Operator (ISO) markets. Specifically, the Commission proposes to relieve market-based rate sellers, i.e., sellers seeking to obtain or retain authorization to make market-based rate sales, of the requirement to submit indicative screens for certain RTO/ISO markets and submarkets.[1] This proposed modification of the Commission's horizontal market power analysis would apply in any RTO/ISO market with RTO/ISO-administered energy, ancillary services, and capacity markets subject to Commission-approved RTO/ISO monitoring and mitigation. In addition, for RTOs and ISOs that lack an RTO/ISO-administered capacity market, market-based rate sellers would be relieved of the requirement to submit indicative screens if their market-based rate authority is limited to sales of energy and/or ancillary services. We believe that this proposal would reduce the filing burden on market-based rate sellers in RTO/ISO markets without compromising the Commission's ability Start Printed Page 994to prevent the potential exercise of market power in RTO/ISO markets.

2. The Commission's regulations would continue to require RTO/ISO sellers [2] to submit indicative screens for authorization to make capacity sales in any RTO/ISO markets that lack an RTO/ISO-administered capacity market subject to Commission-approved RTO/ISO monitoring and mitigation. We also propose 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.

II. Background

A. The Market-Based Rate Program

3. In Order No. 697,[3] the Commission codified two indicative screens for assessing horizontal market power for market-based rate sellers: The pivotal supplier screen and the wholesale market share screen (with a 20 percent threshold), each of which serves as a cross check on the other to determine whether sellers may have market power and should be further examined.[4] The Commission stated that passage of both indicative screens establishes a rebuttable presumption that the seller does not possess horizontal market power. Sellers that fail either indicative screen are rebuttably presumed to have market power and have the opportunity to present evidence through a delivered price test (DPT) analysis or other evidence demonstrating that, despite a screen failure, they do not have market power.[5] The Commission uses a “snapshot in time” approach based on historical data for both the indicative screens and the DPT analysis.[6]

4. With respect to the horizontal market power analysis, in traditional markets (outside RTO/ISO markets) the default relevant geographic market for purposes of the indicative screens is first, the balancing authority area(s) where the seller is physically located, and second, the markets directly interconnected to the seller's balancing authority area (first-tier balancing authority areas).[7] Generally, sellers that are located in and are members of an RTO/ISO may consider the geographic region under the control of the RTO/ISO as the default relevant geographic market for purposes of the indicative screens.[8]

5. In Order No. 697, the Commission created two categories of market-based rate sellers.[9] Category 1 sellers are wholesale power marketers and wholesale power producers that own, control, or are affiliated with 500 megawatts (MW) or less of generation in aggregate per region; that do not own, operate, or control transmission facilities other than limited equipment necessary to connect individual generation facilities to the transmission grid (or have been granted waiver of the requirements of Order No. 888 [10] ); that are not affiliated with anyone that owns, operates, or controls transmission facilities in the same region as the seller's generation assets; that are not affiliated with a franchised public utility in the same region as the seller's generation assets; and that do not raise other vertical market power issues.[11] Category 1 sellers are not required to file regularly scheduled updated market power analyses. Market-based rate sellers that do not fall into Category 1 are designated as Category 2 sellers and are required to file updated market power analyses every three years.[12] However, the Commission may require an updated market power analysis from any market-based rate seller at any time, including those sellers that fall within Category 1.[13]

6. Section 35.37 of the Commission's regulations requires market-based rate sellers to submit market power analyses: (1) When seeking market-based rate authority; (2) every three years for Category 2 sellers; and (3) at any other time the Commission requests a seller to submit an analysis. A market power analysis must address a market-based rate seller's potential to exercise horizontal and vertical market power. If a market-based rate seller studying an RTO/ISO market as a relevant geographic market fails the indicative screens for the RTO/ISO market, it can seek to obtain or retain market-based rate authority by relying on Commission-approved RTO/ISO monitoring and mitigation.[14]

B. Order No. 816 [15] Proposal

7. On July 19, 2014, the Commission proposed certain changes and clarifications in order to streamline and improve the market-based rate program's processes and procedures.[16] The Commission found that the burdens associated with certain requirements may outweigh the benefits in certain circumstances. For those reasons, the Commission proposed changes to the market-based rate program that the Commission believed would reduce burden, while continuing to ensure that the standards for market-based rate sales result in sales that are just and reasonable.

8. The Commission noted that since the issuance of Order No. 697, it has been the Commission's practice to grant sellers market-based rate authority or allow them to retain market-based rate authority where they have failed indicative screens in an RTO/ISO market but have relied on Commission-approved monitoring and mitigation to mitigate any market power that the Start Printed Page 995sellers may have.[17] The Commission found that the existence of market monitoring and mitigation in an organized market generally results in transparent prices, which discipline forward [18] and bilateral markets by revealing a benchmark price and keeping offers competitive.[19] While the burdens of preparing the indicative screens are not necessarily greater for RTO/ISO sellers than for market-based rate sellers in other markets, in the Order No. 816 NOPR, the Commission noted that the submission of indicative screens yields little practical benefit because it has been the Commission's practice to allow RTO/ISO sellers that fail the indicative screens to rely on RTO/ISO monitoring and mitigation to mitigate any market power that the sellers may have. Thus, for market-based rate sellers in RTO/ISO markets, the Commission stated that “the burden of submitting indicative screens may not be `outweighed by the additional information gleaned with respect to a specific seller's market power.’ ” [20]

9. Specifically, as relevant for the purposes of the instant NOPR, the Commission proposed in the Order No. 816 NOPR to allow market-based rate 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.[21] Under that proposal, RTO/ISO sellers 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 market-based rate seller at any time.[22]

C. Comments on Order No. 816 Proposal

10. The Commission received numerous comments on its proposal to eliminate the need for RTO/ISO sellers to submit indicative screens as part of their market power analyses. As discussed below, some commenters supported the Commission's proposal; [23] other commenters requested that the Commission clarify aspects of its proposal,[24] or extend the proposal to additional circumstances.[25] However, some commenters opposed the Commission's proposal, raising issues regarding the Commission's legal authority to eliminate the requirement to submit indicative screens [26] or the effectiveness of RTO/ISO monitoring and mitigation.[27]

11. Numerous commenters supported the Commission's proposal. AEP urged the Commission to adopt the proposal, stating that “[t]he nature of the current RTOs, with large markets, transparent pricing and vigorous, independent monitoring and mitigation measures, provides sellers with incentives to offer competitive prices” and noted that “[c]ustomers will not be harmed if the current reporting requirements are narrowed as proposed.” [28] EPSA also agreed that the indicative screen requirement “yields little practical benefit because, according to current market power screen rules, if a seller in an RTO/ISO market does fail the indicative screens, the Commission has allowed such sellers to rely on Commission-approved market monitoring and mitigation as a default.” [29] The Commission's proposal was also supported by E.ON, SoCal Edison, Solomon/Arenchild, SunEdison, and NRG.[30]

12. Several other commenters supported the proposal and made additional proposals. For example, Golden Spread supported the proposal but requested that the Commission “afford RTO/ISO market participants or interested stakeholders that have concerns about market power the opportunity to come forward and present evidence that a specific market participant or market participants in a specific RTO/ISO generally have the ability to exercise generation market power.” [31] FirstEnergy supported the proposal but also argued that a seller should no longer be required to file a change in status report based on increases in the amount of generating capacity that it owns or controls once it has made an affirmative statement that it is selling electricity in RTO markets with Commission-approved market monitoring and mitigation practices and the Commission has accepted that statement as sufficient to address horizontal market power concerns.[32]

13. In addition, EEI requested that the Commission “provide the same relief from undertaking the horizontal market power screens outside RTOs, to utilities that have accepted FERC-approved market power mitigation measures that are intended to address market power concerns in specific balancing authority areas [. . .], markets, or regions.” [33] Similarly, El Paso, while not suggesting that third-party market monitoring suffices to eliminate the indicative screen requirement, stated that, where a non-RTO market has third-party market monitoring of a size and scope comparable to that of an RTO (“i.e., with hourly testing of horizontal market power over the price of energy, accompanied by FERC-approved automatic mitigation”), and when public utility sellers with such Commission-approved measures in place are not seeking to rebut the Commission's pre-existing presumption of market power or the associated Commission-approved measures, “it may be appropriate for the utilities to provide, in their triennial submissions, only the asset appendices and descriptions that would be required for [s]ellers within RTOs, for the sake of comparability.” [34]

14. NextEra supported the proposal and asked the Commission to clarify Start Printed Page 996that the Order No. 816 NOPR did not intend to eliminate the rebuttable presumption regarding Commission-approved RTO monitoring and mitigation that was developed in Order No. 697-A.[35] Potomac Economics agreed with the proposed reforms, but recommended that the Commission “take steps to ensure that the market mitigation measures for each RTO are complete and effective.” [36] SoCal Edison sought clarification that entities participating in the California Independent System Operator Corporation (CAISO) Energy Imbalance market must still perform screens for their “home” market and that such market has not been expanded to include CAISO.[37]

15. Several commenters opposed the proposal citing legal, economic, or implementation issues. APPA/NRECA contended that the proposal represented a fundamental departure from the market-based rate scheme that the courts have previously upheld [38] and objected on the following grounds: (1) The proposed rule provides no legal or factual analysis showing that RTO mitigation standing alone is legally sufficient to allow market-based pricing; [39] (2) the proposed rule would effectively deregulate public utilities' bilateral sales in RTO regions; [40] and (3) the proposal would unlawfully subdelegate to private entities, i.e., RTOs, the Commission's statutory responsibilities to ensure that wholesale electric rates of public utilities are just and reasonable.[41] APPA/NRECA also argued that recent experience suggests that RTO mitigation has not been adequate to prevent the exercise of individual seller market power.[42]

16. AAI stated that the proposal “would relinquish perhaps the most important tool the Commission has to prevent abusive conduct before it occurs—namely the ability to deny market-based rate authority based on an ex ante showing that a generator possesses market power.” [43] AAI further contended that the Commission has “largely outsourced the oversight of monitoring and mitigation” to the RTO market monitors and that the proposal to eliminate the horizontal market power indicative screens “would seem to compound the Commission's already significant distance from this crucial area of oversight.” [44] AAI also stated that the information submitted as part of the screens provides information and insight that the Commission can use to improve and refine policies to prevent transmission owners from discriminating against rival generators and that “[c]easing to collect this critical information would do a disservice to competition and consumers.” [45]

17. TAPS stated that, even if RTO monitoring and mitigation is effective to mitigate market power today, “that may not [be] true going forward, and the Commission should not blind itself to the extent of seller market power in a particular RTO” and that “[t]he Commission should not and cannot properly rely on Commission-approved market monitoring and mitigation in organized markets or market forces to safeguard against the exercise of market power in bilateral and forward markets.” [46] TAPS stated that “Order No. 697-A's pronouncements with respect to bilateral and forward markets are a compelling reason to continue to require the submission of indicative screen data” and that if the Commission removes the requirement for RTO/ISO sellers to submit indicative screens, “the Commission will need to revisit Order [No.] 697's treatment of [market-based rates] for forward and bilateral sales in RTO regions in light of the removal of an essential element of the support for that disposition.” [47]

18. TAPS also stated that it is problematic for the Commission to rely on the “faulty presumption” that organized spot markets will discipline forward and bilateral markets by revealing benchmark prices “given the non-substitutable nature of the products.” [48] TAPS contended that Order No. 697 relied on the Commission's market power screening combined with Commission-approved monitoring and mitigation to support market-based rates in bilateral markets, pointing to the ability of customers to challenge the RTO mitigation in the context of market-based rate applications and triennial reviews informed by the screen information: “[t]he NOPR, however, would completely remove this important avenue to assure just and reasonable rates on bilateral contracts that the Commission has sought to promote.” [49]

19. EPSA filed comments in reply to APPA/NRECA and Potomac Economics. EPSA disagreed with APPA/NCRECA's assertion that relying on mitigation measures under the various RTO tariffs in lieu of market power analyses represents a departure from the market-based rate scheme that the courts have previously upheld, because the Commission adopted the rebuttable presumption in Order No. 697-A, if not earlier.[50] EPSA also takes issue with APPA/NRECA's argument that the proposed rule would effectively deregulate public utilities' bilateral sales in RTO regions, arguing that the Commission in Order No. 697-A explained that RTO/ISO mitigation measures act as a disciplining force even with respect to sales negotiated on a bilateral basis, and further explained Start Printed Page 997that “RTO/ISOs have Commission-approved market mitigation rules that govern behavior and pricing in those short-term markets,” and that “the RTO/ISOs have Commission-approved market monitoring, where there is continual oversight to identify market manipulation.” [51]

20. EPSA also argued that the proposal would not unlawfully subdelegate to private entities, i.e., RTOs, the Commission's statutory responsibilities to ensure that wholesale electric rates of public utilities are just and reasonable, as APPA/NRECA argued, noting that nothing in the proposed rule seeks any change to the Commission's extensive oversight over RTO and ISO markets, and that the Commission will “continue to evaluate and approve or reject the proposed market rules for each RTO/ISO, monitor RTO/ISO implementation of such rules, and hear challenges regarding the effectiveness of RTO/ISO mitigation measures.” [52]

21. EPSA disagreed with Potomac Economic's recommendation that the Commission take steps to ensure that the market mitigation measures for each RTO are complete and effective, stating that like APPA and NRECA, “Potomac Economics appears to miss the point that the rebuttable presumption was adopted years ago in Order No. 697-A, and its objection to that presumption is an impermissible collateral attack on that order.” [53]

22. 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.[54] We have reviewed and considered that record in preparing the instant proposal.

III. Discussion

23. After reviewing all of the comments received in response to the Order No. 816 NOPR, we believe that it is appropriate to relieve market-based rate sellers of the requirement to submit the indicative screens in certain circumstances. As discussed below, the proposal we make here differs in some material respects from the original proposal in the Order No. 816 NOPR. Specifically, the Commission proposes to relieve market-based rate sellers, i.e., sellers seeking to obtain or retain authorization to make market-based rate sales, of the requirement to submit indicative screens for certain RTO/ISO markets and submarkets. This proposed modification of the Commission's horizontal market power analysis would apply in any RTO/ISO market with RTO/ISO-administered energy, ancillary services, and capacity markets subject to Commission-approved RTO/ISO monitoring and mitigation. In addition, for RTOs and ISOs that lack an RTO/ISO-administered capacity market, market-based rate sellers would be relieved of the requirement to submit indicative screens if their market-based rate authority is limited to sales of energy and/or ancillary services.

24. Under this proposal, the Commission's regulations would continue to require RTO/ISO sellers [55] to submit indicative screens for authorization to make capacity sales in any RTO/ISO markets that lack an RTO/ISO-administered capacity market subject to Commission-approved RTO/ISO monitoring and mitigation. Furthermore, we propose 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.

25. Although this proposal would eliminate the requirement to submit indicative screens in certain RTO/ISO markets, it would not eliminate other market-based rate regulatory reporting requirements. As discussed below, we believe that the RTO/ISO market power monitoring and mitigation combined with the remaining market-based rate reporting requirements will enable the Commission to adequately address market power concerns in the RTO/ISO markets.

A. Overview of Existing RTO/ISO Market Power Monitoring and Mitigation

26. Both the horizontal market power analysis, including indicative screens, and RTO/ISO market power monitoring and mitigation provisions are designed to protect against the potential exercise of seller market power, and the Commission has found that both ensure just and reasonable rates. The indicative screens provide an up-front snapshot of the seller's market power, using static and historical data aggregated from a specific year, which is part of the basis of the Commission's determination of whether to grant that seller market-based rate authority. RTO/ISO market power mitigation is based on real-time data, and is triggered in response to specific resource offers or system characteristics and tailored to the market rules of each RTO/ISO.

27. Despite these differences, the market power analyses provided in the indicative screens and RTO/ISO market power mitigation both seek to prevent the exercise of seller market power and ensure just and reasonable rates. Given the Commission's previous findings that RTO/ISO monitoring and mitigation adequately mitigate a seller's market power and the availability of other data regarding horizontal market power, the indicative screens provide marginal additional market power protections and these protections will still be available with the proposed changes.[56] This suggests that the burden on sellers to provide indicative screens may outweigh the benefits in certain RTO/ISO markets.

28. RTO/ISO market power mitigation is ongoing and tailored to the specific RTO/ISO and uses more granular operational or market data than the indicative screens. This data is used to specifically tailor the RTO/ISO market power screens to the market interval (and sometimes a few subsequent intervals) for which prices are established.[57] Given the dynamic nature of binding transmission constraints and ever-changing market conditions, the RTO/ISO market power mitigation generally allows for a flexible and ongoing application of market power tests, which more accurately reflect system conditions that exist at the time and are better suited to preventing the exercise of market power in the RTO/ISO markets than the static indicative screens that are in many cases only filed every three years. In the event that a seller in an RTO/ISO market fails the RTO/ISO market power mitigation tests, that seller's offer is mitigated to a reference level or cost-based offer, Start Printed Page 998which represents the resource's short-run marginal cost.

29. CAISO and PJM use a structural approach to market power mitigation, imposing mitigation when a resource's offer fails a market power screen that relies on the three pivotal supplier test to measure competition. In contrast, ISO-NE, MISO, NYISO, and Southwest Power Pool, Inc. (SPP) employ a conduct and impact approach to market power mitigation, using a two-part market power screen that includes (1) a conduct test, which compares a resource's offer to its reference level,[58] and (2) an impact test, which examines the extent to which that offer affects clearing prices, mitigating an offer if it fails both tests.

30. Identification of constrained areas is a fundamental aspect of RTO/ISO market power mitigation. For example, the RTO/ISOs with conduct and impact mitigation generally use more stringent conduct and impact tests in areas that are more significantly or frequently constrained. The definition of a constraint, or its treatment as static or dynamic,[59] and the conduct and impact thresholds vary by RTO/ISO. PJM uses a three pivotal supplier test to evaluate whether sellers are likely to be able to exercise market power and applies this test any time a resource is committed from an offline state to relieve a binding transmission constraint. In CAISO, a resource's energy supply offer is subject to market power mitigation if that resource's offer affects a transmission constraint deemed by CAISO to be non-competitive.

31. The Commission also requires the RTO/ISO independent market monitors to evaluate market monitoring and mitigation efforts on an ongoing basis. Market monitors are required to periodically report on the performance of market power mitigation practices, evaluate tariff inadequacies or proposals, and report on the general competitiveness of their respective markets.[60] Market monitors report information on how the competitiveness of the RTO/ISO market or any relevant sub-markets is affected by transmission constraints and report a variety of competition metrics,[61] including the Herfindahl-Hirschman Index (HHI), supply-side and demand-side concentration measurements,[62] pivotal supplier tests,[63] the residual supplier index,[64] and the Lerner index.[65]

32. We summarize below the specific market power mitigation provisions used today by RTO/ISOs to prevent the exercise of market power in energy, ancillary services, and capacity markets.

1. Energy

33. All RTOs/ISOs have mitigation provisions for energy offers, which generally are employed when there are binding constraints on the system.[66] Energy supply offers, which include both financial and physical offer components, are screened for potential market power. Financial offer components are denominated in dollars. The most important financial offer components are the start-up, no-load, and incremental energy offers, all of which are subject to mitigation. Physical offer components are denominated in non-dollar units, such as MW, time, or some combination thereof (e.g., minimum run time, economic minimum operating level, ramp rate). When a resource's offer fails the applicable market power screens, that offer is mitigated.

34. Market power mitigation often involves replacing the seller's offer with an appropriate reference level to determine the locational market price. Reference levels for financial offer components are based on an estimate of a resource's short-run marginal cost, and reference levels for physical offer components are based on an estimate of the physical capability of a resource. Reference levels are determined either by the seller of the resource pursuant to guidelines and review (e.g., SPP) [67] or by the market monitor, potentially after consultation with the seller (e.g., CAISO).[68] In many cases, the market monitors help create the resource-specific reference levels with the seller.

35. In addition to market power mitigation provisions, resource offers in energy markets are subject to an offer cap. Pursuant to Order No. 831,[69] the RTO/ISO or market monitor must verify energy supply offers above $1,000/MWh prior to those offers being used to calculate locational marginal prices (LMPs). Order No. 831 also requires each RTO/ISO to limit energy supply offers to $2,000/MWh (known as the “hard cap”) when calculating LMPs.[70]

36. Resources with capacity supply obligations in RTOs/ISOs also are subject to must-offer requirements, which are designed to address physical withholding.[71]

2. Ancillary Services

37. Unlike the market-based rate indicative screens, which do not specifically analyze market power for ancillary services, RTO/ISO market power mitigation provisions are designed to address the specific ancillary service products that are sold in the RTO/ISO. The market power mitigation provisions for ancillary services in four RTOs/ISOs (NYISO, PJM, MISO, and SPP) are similar to market power mitigation for energy and employ either conduct and impact screens or structural market power screens to identify and potentially mitigate offers of ancillary services that raise market power concerns.

38. Although CAISO and ISO-NE do not have market power mitigation provisions in place for ancillary services,[72] as noted above, ancillary Start Printed Page 999service prices typically are based on the opportunity cost of not generating energy, so concerns about market power in ancillary service offers in these RTOs/ISOs are alleviated through the mitigation of energy offers.[73] In addition, these markets are still monitored by their respective independent market monitors,[74] enabling the CAISO and ISO-NE market monitors to evaluate the competitiveness of their respective ancillary service markets and submit a filing at the Commission to seek changes if they deem them necessary.

39. In addition, Commission staff and third parties retain the right at any time to provide evidence that a particular seller in an RTO/ISO has market power in ancillary services that is not adequately mitigated by the existing market rules. Moreover, unlike the capacity market issues discussed below, remedies for any gaps in ancillary service market mitigation can be addressed more readily because CAISO and ISO-NE currently operate ancillary service markets and thus have the ability to propose market power mitigation provisions for ancillary services should additional mitigation be warranted.

3. Capacity

40. The indicative screens analyze the uncommitted capacity of a market-based rate seller in each RTO/ISO, without regard to a specific offer and do not take specific locational requirements or performance obligations into account. By contrast, ISO-NE, NYISO, PJM and MISO currently operate capacity markets with Commission-approved market power mitigation for a standardized RTO/ISO capacity product that specifies a particular delivery year and capacity supply obligation. Capacity sales in RTO/ISOs that operate capacity markets also are subject to system-wide offer caps. If a seller wants to offer its unit at a price higher than the cap, it must submit its costs to the market monitor and have a reference level developed based on its going-forward cost, which becomes its maximum offer.[75]

41. CAISO and SPP do not operate centralized capacity markets currently; thus, they do not have mitigation in place for capacity sales. We note that the California Public Utilities Commission plays an active role in reviewing the majority of bilateral capacity contracts (i.e., Resource Adequacy contracts) in CAISO because the costs of these contracts are recovered in retail electric rates. Similarly, capacity costs in the SPP footprint are reviewed by state regulators and recovered through cost-of-service rates. As such, the market for capacity as a standalone product in SPP is very small. Although the CAISO and SPP capacity contracts are subject to state oversight, as explained above, at this time we propose that the requirement to submit the indicative screens be retained for market-based rate sellers studying RTO/ISO markets that do not include RTO/ISO-administered capacity markets, including CAISO and SPP, unless the seller is only making energy and/or ancillary service sales and not capacity sales.[76]

B. Proposal Implementation

42. We propose two modifications to § 35.37(c) of the Commission's regulations to exempt certain market-based rate sellers from the requirement to submit the indicative screens as part of their horizontal market power analyses of RTO/ISO markets, whether as part of an initial application for market-based rate authority, a change in status filing, or an updated market power analyses.

43. First, for entities seeking to sell into RTO/ISO-administered energy, ancillary services, and capacity markets, a market-based rate seller could state that it is relying on Commission-approved RTO/ISO market monitoring and mitigation, which is presumed to address any potential horizontal market power that the seller might have in such markets.[77] This modification would apply equally to sellers that study an RTO/ISO market as a first-tier market. A power marketer likewise could represent that it is relying on RTO/ISO market monitoring and mitigation in any RTO/ISO market that is a relevant geographic market for the power marketer.[78] To implement this proposal, we propose to insert a new paragraph in § 35.37(c) specifying that, in lieu of submitting the indicative market power screens, sellers studying RTO/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.

44. Second, we also propose that sellers in RTOs and ISOs that lack an RTO/ISO-administered capacity market would be relieved of the requirement to submit the indicative screens if their market-based rate authority is limited to wholesale sales of energy and ancillary services. To implement this proposal, we propose to insert a second new paragraph in § 35.37(c) specifying that, in lieu of submitting the indicative market power screens, sellers studying RTO/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.

45. We believe that these exemptions will reduce the burden on market-based rate sellers while preserving appropriate Commission oversight of its market-based rate program. Since the issuance of Order No. 697 in 2007, the Commission has granted sellers market-based rate authority, or allowed them to retain market-based rate authority, where they have failed the indicative screens in an RTO/ISO but have relied on Commission-approved RTO/ISO Start Printed Page 1000monitoring and mitigation.[79] Given the Commission's presumption that RTO/ISO market monitoring and mitigation adequately mitigate any potential seller market power, the submission of the indicative screens yields little practical benefit when compared to the associated burden on industry. This burden is not trivial; over the three-year period 2015-2018, market-based rate sellers in RTOs/ISOs filed approximately 130 indicative screens in updated market power studies for RTOs/ISOs on average per year.[80] We provide more detailed information on the burden associated with filing indicative screens for updated market power studies in the Information Collection Statement section below.

46. However, market-based rate sellers still would be required to file initial applications, changes in status, and triennial updates, including all of the information currently required, except the seller would not need to submit indicative screens for any RTO/ISO markets subject to the above-proposed exemptions. Specifically, to address horizontal market power in an RTO/ISO market, a seller's initial application for market-based rate authorization and any subsequent updated market power analyses would include, among other things: (1) A statement that the seller is relying on Commission-approved RTO/ISO market monitoring and mitigation to address any potential market power it might have in that market; (2) identification and description of it and its affiliates' generation and transmission assets and other inputs to electric power production; and (3) an asset appendix as required in 18 CFR 35.37(a)(2).[81] The Commission believes that the continued submission of information, such as the asset appendix and Electric Quarterly Reports (EQR),[82] will help us to maintain effective oversight of RTO/ISO markets. Moreover, under this proposal, the Commission would retain the ability to require an updated market power analysis, including indicative screens, from any market-based rate seller at any time.

47. In addition, the Commission proposes to continue requiring RTO/ISO sellers to submit change in status filings consistent with current requirements. While we received comments from the Order No. 816 NOPR that called for eliminating the change in status requirement for RTO/ISO sellers, we believe the change in status requirement is an important tool that the Commission uses to identify new potential market power concerns, which will assist the Commission in ensuring that rates continue to be just and reasonable. Under this proposal, we would still require an RTO/ISO seller to report any change in status that would reflect a departure from the characteristics that the Commission relied upon in granting it market-based rate authority, as required under § 35.42 of the Commission's regulations. Therefore, consistent with current policy, where the change in status concerns pertinent assets held by that seller or its affiliates, the seller must still submit a new asset appendix.[83]

48. Although market-based rate sellers are not required to provide indicative screens in their horizontal market power analyses when submitting change in status filings,[84] sellers often submit indicative screens in order to determine the effect of the change on their market power, particularly when a change in status filing has created the likelihood that they would fail an indicative screen. We clarify that, with this proposed streamlined approach, an RTO/ISO seller subject to the proposed exemption in this NOPR also would not need to submit indicative screens with its change in status filing even where it may have market power. Instead, the seller may state that it is relying on Commission-approved monitoring and mitigation to mitigate any potential market power it may have.

49. However, in RTOs/ISOs that do not operate an RTO/ISO-administered capacity market with Commission-approved mitigation, we propose to continue to require the submission of the indicative screens for any seller seeking to make market-based sales of capacity. CAISO and SPP currently are the RTO/ISO markets without an RTO/ISO-administered capacity market. Therefore, we propose to require any seller seeking to sell capacity at 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.

50. We recognize that there is state regulatory oversight of the capacity costs and/or prices incurred in CAISO and SPP. However, we do not believe that it is appropriate to exempt sellers from filing the indicative screens (i.e., submitting a horizontal market power study) in markets that lack Commission-approved monitoring and mitigation programs. Capacity markets are distinct from energy markets (unlike several ancillary services, capacity is not co-optimized with energy),[85] so monitoring and mitigation of energy prices in day-ahead and real-time markets does not ensure that capacity prices will be just and reasonable. Therefore, we believe that the indicative screens remain an important tool for determining whether a seller has market power in RTO/ISO markets that lack Commission-approved market monitoring and mitigation for capacity sales.

51. Thus, we are proposing that indicative screen failures in RTO/ISO markets that do not have RTO/ISO-administered capacity markets (currently, CAISO and SPP) will no longer be presumed to be adequately addressed by RTO/ISO market monitoring and mitigation. We propose that any market-based rate seller that Start Printed Page 1001fails the indicative screens in those markets and seeks to rebut the presumption of horizontal market power may submit a DPT or alternative evidence or propose other mitigation for capacity sales in these markets.

52. In contrast, we do not propose to disturb the rebuttable presumption in RTOs/ISOs with RTO/ISO-administered energy, ancillary services, and capacity markets. In addition, we do not propose to disturb the rebuttable presumption for market-based sales of energy and ancillary services in RTO/ISO markets that have monitoring and mitigation for these two services. In those RTOs/ISOs, Commission-approved monitoring and mitigation is currently presumed to adequately address market power concerns presented by indicative screen failures. To the extent that commenters are arguing that it is inappropriate for the Commission to rebuttably presume that market monitoring and mitigation is sufficient to mitigate any market power a seller may have in an RTO/ISO market, we believe that it is a collateral attack on the Commission's creation of the rebuttable presumption in Order No. 697-A.[86]

53. As noted above, we propose to maintain the rebuttable presumption that Commission-approved monitoring and mitigation is currently presumed to adequately address market power concerns. By its terms, the rebuttable presumption established in Order No. 697-A that existing RTO/ISO monitoring and mitigation is sufficient to address market power concerns is not immune to challenge. The Commission and intervenors can rebut this presumption in a particular case using information market-based rate sellers provide in accordance with § 35.37 in their initial applications, change in status filings and triennial updated market power analyses.[87] The challenging party would bear the burden of proof to demonstrate that the seller has market power and that such market power is not addressed by existing Commission-approved RTO/ISO market monitoring and mitigation.

54. We seek comment as to whether CAISO or SPP currently have adequate additional safeguards in place that prevent the exercise of horizontal market power in sales of capacity. Commenters who argue that adequate safeguards are present should explain in detail why the Commission should find the requirement to submit indicative screens to be unnecessary for capacity sales in either of these markets. If either CAISO or SPP adopts an RTO/ISO-administered capacity market with Commission-approved monitoring and mitigation in the future, the Commission could revisit the requirement that sellers of capacity submit the indicative screens.

55. We are not proposing to relieve market-based rate sellers of the requirement to submit the indicative screens in any market outside of an RTO/ISO, even a market that may have an alternative form of mitigation. As explained above, RTO/ISO monitoring and mitigation is comprehensive and specifically tailored to each RTO/ISO market. Such mitigation, particularly the ability to mitigate prices on an ongoing basis, does not exist in any non-RTO/ISO market.

C. Bilateral Transactions

56. Market-based rate sellers may enter into bilateral transactions for energy, capacity, and ancillary services within RTO/ISO footprints. Although such transactions are not monitored or mitigated by RTOs/ISOs, the proposal will not give rise to market power concerns with respect to bilateral transactions, as discussed below.

57. Wholesale buyers and sellers of energy and capacity enter into various types of bilateral financial and physical instruments, including forward contracts that settle on day-ahead and real-time electricity prices. An electricity forward contract represents the obligation to buy or sell a fixed amount of electricity at a pre-specified contract price, i.e., the forward price, at a certain time in the future.[88] Forward contracts involve a transaction between a specific buyer and seller, unlike the day-ahead and real-time RTO/ISO energy markets which are bid- and offer-based markets that are centrally cleared.

58. The price of a forward contract represents the willingness of buyers and sellers to exchange electricity in the future and should largely reflect expectations of future demand and supply conditions in RTO/ISO markets if markets are liquid and competitive. Thus, if RTO/ISO energy (e.g., day-ahead and real-time) markets and capacity markets are competitive, and Commission-approved monitoring and mitigation sufficiently protects against the exercise of market power in these markets, then bilateral markets for the same product should also be competitive. Moreover, the structure of RTO/ISO markets enhances competition in the forward markets because entities that do not have physical assets or load (e.g., marketers) can rely on the RTO/ISO to physically deliver the power while settlement prices in RTO/ISO markets enable financial transactions.[89]

59. RTO/ISO day-ahead and real-time energy markets and capacity markets also can provide an alternative to bilateral sales,[90] thereby helping to discipline prices on bilateral contracts for energy and capacity. For these reasons, the existence of competitive RTO/ISO markets is expected to provide a strong incentive for sellers in bilateral markets to offer at competitive prices.

60. Contrary to some comments received in the Order No. 816 proceeding, we believe that the proposal will retain sufficient Commission oversight of bilateral sales in RTO/ISO markets. As the Commission previously has explained, the existence of market power mitigation in an organized market generally results in a market where prices are transparent, which disciplines forward and bilateral markets by revealing a benchmark price, keeping offers competitive.[91] In addition, as the Commission has previously found, buyers seeking bilateral transactions in RTO/ISO footprints “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.” [92] The Commission also retains the ability to require the submission of indicative screens should evidence of market power in the bilateral markets materialize.

Start Printed Page 1002

D. The Commission Will Continue To Ensure That Market-Based Rates Are Just and Reasonable

SUPRA

61. Notwithstanding concerns raised in response to the Order No. 816 NOPR,[93] we believe that the Commission's market-based rate program and its broader oversight of RTO/ISO markets, including its enforcement authority, is sufficiently robust to check the potential exercise of market power without the need for the indicative screens addressed in this NOPR. As discussed in Order No. 697, “the Commission's market-based rate program includes many ongoing regulatory protections designed to ensure that rates are just and reasonable and not unduly discriminatory or preferential.” [94] Exempting sellers from submitting screens for RTO/ISO markets will not eliminate these other requirements set forth in § 35.37 of the Commission's regulations.

62. Such protections include the requirement for sellers with market-based rate authority to submit EQRs, notices of change in status, and the requirement to submit a market power analysis, which would still include an asset appendix, affiliate information, and a demonstration regarding vertical market power.[95] We believe that the asset appendix provides comprehensive information relevant to a determination of a seller's market power, including information on: generators owned or controlled by seller and its affiliates; long-term firm power purchase agreements of seller and its affiliates; and electric transmission assets, natural gas intrastate pipelines, and intrastate natural gas storage facilities owned or controlled by seller and its affiliates.[96] The asset appendix information on generation and power purchase agreements are important parts of any assessment of horizontal market power and the information on electric transmission and intrastate gas facilities support the analysis of vertical market power.[97] Thus, we do not believe that eliminating the requirement that sellers submit indicative screens in certain RTO/ISO markets would mean that the Commission and others would lack information necessary to assess a seller's horizontal market power. In addition, under this proposal, the Commission would continue to reserve the right to require submission of complete horizontal market power analysis, including indicative screens, at any time.[98]

63. Asset and ownership information would also continue to be collected as part of initial applications, as well as change in status filings [99] in which sellers report, among other things, changes with respect to their and their affiliates': (1) Ownership or control of generation capacity or long-term firm purchases of capacity and/or energy that result in a cumulative net increase in 100 MW or more of capacity in any relevant geographic market (including an RTO/ISO market); (2) ownership or control of inputs to electric power production or ownership, operation or control of transmission facilities; and (3) affiliation with any entity that: (a) Owns or controls generation facilities or has long term firm purchases of capacity or energy that results in cumulative net increases of 100 MW or more in a relevant geographic market; (b) owns or controls inputs to electric power production; (c) owns, operates, or controls transmission facilities; or (d) has a franchised service area.

64. In addition, the Commission's regulations require public utilities to file EQRs,[100] which summarize transaction information for cost-based and market-based rate sales and contractual terms and conditions in the public utility's agreements for jurisdictional services.[101] The data collected in EQRs provide information that the Commission needs to perform its regulatory functions and “provide[s] greater price transparency, promote[s] competition, enhance[s] confidence in the fairness of the markets, and provide[s] a better means to detect and discourage discriminatory practices.” [102] The EQR also “strengthens the Commission's ability to identify potential exercises of market power or manipulation and to better evaluate the competitiveness of interstate wholesale electric markets.” [103] Nothing in the Commission's proposal here affects the EQRs; thus, EQRs would remain available for the Commission and others to use to detect the potential exercise of market power. Indeed, the EQR data is a critical component of the Commission's market oversight activities, which aim, among other things, to identify potential opportunities for the exercise of market power.

65. Furthermore, nothing in this proposal would prevent the Commission or others from initiating a proceeding under Federal Power Act section 206 if concerns are identified about a seller's market power or the ability of RTO/ISO market monitoring and mitigation to address any such market power.

66. Although it is true that the Commission would not receive the indicative screens for market-based rate sellers in certain RTO/ISO markets under this proposal, we do not believe that this would affect the Commission's ability to prevent and deter abusive conduct. In fact, the Commission-approved RTO/ISO market monitoring and mitigation in large part is designed to do just that—prevent the exercise of market power before it happens. As discussed above, the RTOs/ISOs screen for potential market power using either a structural test such as the three pivotal supplier screen or a conduct and impact Start Printed Page 1003test, which first compares a resource's offer to its reference level and then examines the extent to which the offer affects market clearing prices.

67. RTO/ISO market power mitigation often involves replacing the offer with an appropriate reference level, which is based on an estimate of the resource's short run marginal cost. Thus, RTO/ISO market power mitigation is intended to prevent the exercise of market power before it can occur, and does so using mitigation that is similar to the Commission's default mitigation for sellers that fail the Commission's market power screens—cost-based mitigation.[104]

68. The Commission's market-based rate regulations also provide that a seller that has been found to have horizontal market power “may propose mitigation tailored to its own particular circumstances to eliminate its ability to exercise market power.” [105] In many ways, RTO/ISO market monitoring and mitigation is just an alternative method that the Commission has approved to mitigate market power that a seller may have in an RTO/ISO market, and this mitigation functions to prevent an exercise of market power before it occurs.

69. We do not believe that the Commission has subdelegated its responsibility with respect to the RTO/ISO markets; to the contrary, it has approved RTO/ISO proposed rules that help ensure that rates for sales in RTO/ISO markets are just and reasonable.[106] As the Commission has previously explained, “Commission-approved RTOs and ISOs run real-time energy markets under Commission-approved tariffs. These single price auction markets set clearing prices on economic dispatch principles, to which various safeguards have been added to protect against anomalous bidding.” [107] Thus, one way in which the Commission ensures just and reasonable rates is through approval of RTO/ISO tariffs.[108]

70. Furthermore, the Commission retains RTO/ISO market oversight through proceedings under Federal Power Act section 206. Specifically, the Commission retains the right to consider whether to institute separate Federal Power Act section 206 proceedings that would be open to all interested entities to investigate whether the existing RTO/ISO mitigation continues to be just and reasonable and, if not, how such mitigation should be revised.[109] In addition, affected parties may argue, in the context of a specific market-based rate application or triennial review, that changed circumstances have rendered such mitigation no longer just, reasonable and not unduly discriminatory. Thus, the Commission takes an ongoing role in ensuring the justness and reasonableness of rates in the RTO/ISO markets.[110]

IV. Information Collection Statement

71. The Paperwork Reduction Act (PRA) [111] 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 [112] require approval of certain information collection requirements imposed by agency rules. 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 these collections of information unless the collections of information display a valid OMB control number.

72. The revisions proposed in this NOPR would clarify and update the requirements specified above 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.[113] The Commission will submit the proposed reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.[114]

73. While the Commission expects that the regulatory revisions proposed herein will reduce the burdens on affected entities, the Commission nonetheless solicits 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 asks that any revised burden or cost estimates submitted by commenters be supported by sufficient detail to understand how the estimates are generated.

74. Section 35.37 of the Commission's regulations currently requires market-based rate sellers to submit a horizontal market power analysis when seeking to obtain or retain market-based rate authority.[115] We propose to implement a streamlined procedure that will eliminate the requirement to file the indicative screens as part of a horizontal market power analysis for any market-based rate seller that studies any RTO/ISO market with RTO/ISO-administered energy, ancillary services, and capacity markets subject to Commission-approved RTO/ISO monitoring and mitigation. Market-based rate sellers that study an RTO, ISO, or submarket therein, would continue to be required to submit indicative screens for authorization to make energy, capacity, or ancillary services sales at market-based rates in any RTO/ISO market that lacks an RTO/ISO-administered energy, capacity, or ancillary services market subject to Commission-approved RTO/ISO monitoring and mitigation. Eliminating the requirement for certain sellers to file indicative screens will reduce the burden of filing a horizontal market power analysis for a large Start Printed Page 1004portion of market-based rate sellers when filing triennial updated market power analyses, initial applications for market-based rate authority, and notices of change in status.

75. Burden Estimate: The estimated burden and cost for the requirements contained in this NOPR follow.[116]

Burden Reductions as Proposed in NOPR in RM19-2-000 [117]

Burden Reductions as Proposed in NOPR in RM19-2-000

RequirementNumber of respondentsAnnual number of responses per respondentTotal number of responsesAverage burden & cost per responseTotal annual burden hours & costAnnual 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 Sellers72172−230 −$21,203−16,560 −$1,526,666−$21,203
Triennial Market Power Analysis Updates for RTO/ISO Sellers33133−230 −$21,203−7,590 −$699,722−$21,203
Total105−24,150 −$2,226,388−$42,406

76. After implementation of the proposed changes, the total estimated annual reduction in cost burden to respondents is $2,226,388 [24,150 hours * $92.19 [118] ) = $2,226,388].

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

Action: Revision of Currently Approved Collection of Information.

OMB Control No.: 1902-0234.

Respondents for this Rulemaking: Public utilities, wholesale electricity sellers, businesses, or other for profit and/or not for profit 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 retain 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, 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.

Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. Please send comments concerning the collection of information and the associated burden estimates to the Commission, and to the Office of Management and Budget, Office of Information and Regulatory Affairs, 725 17th Street NW, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-4638, fax: (202) 395-7285]. For security reasons, comments to OMB should be submitted by email to: oira_submission@omb.eop.gov. Comments submitted to OMB should include Docket Number RM14-14, FERC-919, and OMB Control Number 1902-TBD.

V. Environmental Analysis

77. 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.[119] The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment.[120] 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 Start Printed Page 1005substantially change the effect of legislation or regulations being amended.[121] In addition, the proposed rule is categorically excluded as an electric rate filing submitted by a public utility under Federal Power Act sections 205 and 206.[122] As explained above, this proposed 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 NOPR.

VI. Regulatory Flexibility Act

78. The Regulatory Flexibility Act of 1980 (RFA) [123] generally requires a description and analysis of proposed rules that will have significant economic impact on a substantial number of small entities. The Commission is not required to perform this sort of analysis if the proposed activities within the NOPR would not have such an effect.

79. Out of the market-based rate filers who are potential respondents subject to the requirements proposed by this NOPR, the Commission estimates approximately 56 percent will be small as defined by SBA regulations.[124]

80. The proposed 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 proposed rule is expected to reduce total annual burden by 24,150 hours per year with a related reduced cost of $2,226,388 per year 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.

81. As discussed in Order No. 697,[125] 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.[126] 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.

82. The proposed rule to no longer require certain RTO/ISO sellers to file indicative screens will reduce the burden on all sellers in RTOs, including small entities in RTOs. The changes to the Commission's regulations for market-based rate sellers are estimated to cause a reduction of 52 percent in total annual burden to market-based rate sellers when filing triennial market power analyses and market power analyses in new applications for market-based rates, including small entities.

83. Accordingly, the Commission certifies that the revised requirements proposed in this NOPR will not have a significant economic impact on a substantial number of small entities, and no regulatory flexibility analysis is required. The Commission finds that the regulations proposed here should not have a significant impact on small businesses.

VII. Comment Procedures

84. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due March 21, 2019. Comments must refer to Docket No. RM19-2-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments.

85. The Commission encourages comments to be filed electronically via the eFiling link on the Commission's website at http://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing.

86. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC, 20426.

87. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

VIII. Document Availability

88. 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.

89. 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.

90. User assistance is available for eLibrary and the Commission's website during normal business hours from the Commission's Online Support at 202-502-6652 (toll free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. Email the Public Reference Room at public.referenceroom@ferc.gov.

Start List of Subjects

List of subjects in 18 CFR Part 35

  • Electric power rates
  • Electric utilities
  • Reporting and recordkeeping requirements
End List of Subjects

By direction of the Commission. Commissioner McIntyre is not voting on this order. Commissioner McNamee is voting present.

Start Signature

Issued: December 20, 2018.

Nathaniel J. Davis, Sr.,

Deputy Secretary.

End Signature

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

Start Part

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

End Part Start Amendment Part

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

End Amendment Part Start Authority

Start Printed Page 1006 Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.

End Authority
[Amended]
Start Amendment Part

2. Amend § 35.37 by redesignating paragraph (c)(5) as (c)(7) and adding new paragraphs (c)(5) and (c)(6) to read as follows:

End Amendment Part
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.

* * * * *
End Supplemental Information

Footnotes

1.  For purposes of this NOPR, references to RTO/ISO markets include any submarkets therein.

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2.  RTO/ISO sellers are market-based rate sellers that have an RTO/ISO market as a relevant geographic market.

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3.  Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, clarified, 121 FERC ¶ 61,260 (2007) (Clarifying Order), order on reh'g, Order No. 697-A, FERC Stats. & Regs. ¶ 31,268, clarified, 124 FERC ¶ 61,055, order on reh'g, Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 (2008), order on reh'g, Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 (2009), order on reh'g, Order No. 697-D, FERC Stats. & Regs. ¶ 31,305 (2010), aff'd sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011), cert. denied, 133 S. Ct. 26 (2012).

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4.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 62.

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5.  Id. P 13; 18 CFR 35.37(c)(3) (2018).

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6.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 17.

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7.  The Commission also noted that “[w]here a generator is interconnecting to a non-affiliate owned or controlled transmission system, there is only one relevant market (i.e., the balancing authority area in which the generator is located).” Id. P 232 n.217.

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8.  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 market-based rate sellers located within the submarket for purposes of the horizontal market power analysis. See id. PP 15, 231.

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9.  Id. P 848.

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10.  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), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, 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 (DC Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

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11.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 849 n.1000; 18 CFR 35.36(a) (2018).

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12.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 850.

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13.  Id. P 853.

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14.  In Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 111, the Commission stated that “to the extent a seller seeking to obtain or retain market-based rate authority is relying on existing Commission-approved [RTO] market monitoring and mitigation, we adopt a rebuttable presumption that the existing mitigation is sufficient to address any market power concerns.”

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15.  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, FERC Stats. & Regs. ¶ 31,374 (cross-referenced at 153 FERC ¶ 61,065) (2015), order on reh'g Order No. 816-A, FERC Stats. & Regs. ¶ 31,282 (2016).

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16.  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, FERC Stats. & Regs. ¶ 32,702 at P 10 (2014) (Order No. 816 NOPR).

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17.  See Order No. 816 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 31. See, e.g., NRG Power Marketing, LLC, 150 FERC ¶ 61,011 (2015) (failures in the CAISO and PJM markets); Entergy Arkansas, Inc., 145 FERC ¶ 61,243 (2013) (failures in the MISO market); PSEG Energy Resources & Trade LLC, 125 FERC ¶ 61,073, at PP 31-32 (2008) (failures in the PJM-East submarket); Dominion Energy Marketing, Inc., 125 FERC ¶ 61,070, at PP 26-27 (2008) (failures in the Connecticut submarket of ISO New England, Inc.); Niagara Mohawk Power Corp., 123 FERC ¶ 61,175, at P 28 (2008) (failures in the New York City and Long Island submarkets of the New York Independent System Operator, Inc.).

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18.  Forward markets are distinct from RTO/ISO-administered capacity markets, as discussed below.

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19.  Order No. 816 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 35.

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20.  Id. P 34 (quoting Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 110).

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21.  See id. PP 35-36.

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22.  Id. P 36.

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23.  See, e.g., American Electric Power Service Corporation (AEP) at 4-5; Electric Power Supply Association (EPSA) at 3-4; FirstEnergy Service Company (FirstEnergy) at 4-5; Subsidiaries of NRG Energy, Inc. (NRG Companies) at 8-9.

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24.  See, e.g., E.ON Climate & Renewables North America LLC (E.ON) at 2-4; Southern California Edison Company (SoCal Edison) at 16; Julie Solomon and Matthew Arenchild (Solomon/Arenchild) at 2; Edison Electric Institute (EEI) at 6; Potomac Economics at 3-4; NextEra Energy, Inc. (NextEra) at 2-3.

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25.  See, e.g., FirstEnergy at 6; AEP at 6; EEI at 7; Golden Spread Electric Cooperative, Inc. (Golden Spread) at 6; El Paso Electric Company (El Paso) at 5-6.

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26.  American Antitrust Institute (AAI) at 2-7; American Public Power Association and National Rural Electric Cooperative Association (APPA/NRECA) at 5-21; Transmission Access Policy Study Group (TAPS) at 1-2, 4-9.

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27.  Potomac Economics at 3-4.

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28.  AEP at 5.

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29.  EPSA at 3-4.

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30.  See E.ON at 2-4, SoCal Edison at 16, Solomon/Arenchild at 2, SunEdison at 1, and NRG at 8-10.

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31.  Golden Spread at 6.

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32.  First Energy at 6.

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33.  Id. EEI also requested that the Commission “clarify that change in status reporting is not required as to changes in any information that would have been used only in the market power indicative screens and analyses, to the extent those screens and analyses are no longer required for particular public utilities in particular [balancing authority areas], markets, or regions.” Id. at 7.

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34.  El Paso at 5-6.

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35.  NextEra at 3 (citing Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 111). NextEra stated that if that is not the case, that the Commission provide a rationale for the change in policy.

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36.  Potomac Economics at 3.

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37.  SoCal Edison at 16.

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38.  APPA/NRECA at 8-10 (citing Mont. Consumer Counsel v. FERC, 659 F.3d 910; California ex rel. Lockyer v. FERC, 383 F.3d 1006 (9th Cir. 2004) (Lockyer); Blumenthal v. FERC, 552 F.3d 875,882 (DC Cir. 2009) (Blumenthal)).

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39.  APPA/NRECA at 10 (“The NOPR does not address the specific mitigation measures of the RTO tariffs where the Commission's proposal would be effective. The NOPR's general statement that RTO market monitoring and mitigation has been `Commission-approved' does not constitute reasoned decision-making [. . .] [T]he Commission approved RTO mitigation [acts] as an addition to—not a substitute for—the Order No. 697 requirement that sellers pass the indicative screens or otherwise demonstrate that they lack or have mitigated their market power. No appellate court precedent supports the lawfulness of market-based rates where the only check on seller market power is RTO mitigation and the Order No. 697 requirements are eliminated.” Id. at 10-11). See also id. at 16-17 (“The adequacy of RTO mitigation of horizontal market power in wholesale electricity is a fact-bound matter. An administrative decision to rely on RTO mitigation of public utility sellers' horizontal market power—even if legally permissible—requires evidence, analysis, and findings of fact and law regarding specific RTO tariffs and markets. But the NOPR provides no such evidence, analysis, or findings.”).

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40.  APPA/NRECA at 11-14 (“[T]he NOPR does not state, much less demonstrate, that this supposed indirect incentive [for a seller to offer at a competitive price] will ensure that the resulting rates for bilateral sales are just and reasonable [. . .] The NOPR's claim that RTO markets will discipline market power in bilateral markets is unsubstantiated and illogical.”) Id. at 12-13.

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41.  APPA/NRECA at 14-16. See also id. at 15 (“ 'The Commission is the only body that can apply and enforce this statutory standard. The Commission cannot subdelegate this core statutory duty to the regulated public utility itself.' ” (citing U.S. Telecom Ass'n v. FCC, 359 F.3d 554, 565-566 (DC Cir. 2004)).

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42.  Id. at 17-21.

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43.  AAI at 3.

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44.  Id. at 4. AAI also stated that there have been several incidents involving the exercise of market power that were in fact not detected or mitigated, citing the proceedings in Docket No. ER14-1409-000, and New York Independent System Operator, Inc., 131 FERC ¶ 61,170 (2010). Id. at 5-6.

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45.  Id. at 6-7.

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46.  TAPS at 1-2.

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47.  Id. at 9.

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48.  Id. at 8 (citing Order No. 816 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 76 (“it is unrealistic for franchised public utilities to rely extensively on spot market purchases to serve statutory load obligations.”)).

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49.  Id. at 8-9.

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50.  EPSA Reply Comments at 4-5. EPSA stated that “APPA and NRECA ignore the fact that the Commission already allows sellers to rely on RTO/ISO mitigation, and that, as the Commission observed in the NOPR, its proposal would do no more than `reflect current practice' in this regard.” Id. at 5.

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51.  Id. at 7-8 (citing Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 285).

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52.  Id. at 9 (citing Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 111).

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53.  Id. at 10.

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54.  Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 27.

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55.  RTO/ISO sellers are market-based rate sellers that have an RTO/ISO market as a relevant geographic market.

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56.  The Commission can still require a market-based rate seller to file indicative screens in individual cases.

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57.  For example, five minutes in the real-time market, one hour in the day-ahead market, and the length of the capacity delivery period for the capacity market. In ISO New England Inc. (ISO-NE), Midcontinent Independent System Operator, Inc. (MISO), and PJM Interconnection, L.L.C. (PJM), the delivery period in the capacity market is one year. In New York Independent System Operator, Inc. (NYISO), the delivery period in the capacity market is one month or six months.

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58.  A reference level is an approximation of a resource's short-run marginal cost.

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59.  RTO/ISO market power mitigation procedures can either identify constraints statically or dynamically. Dynamically identified constraints are designated based on constantly evolving system congestion patterns, whereas statically identified constraints are designated following an ex post review of congestion patterns on an annual or at times less frequent basis.

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60.  RTO/ISO market monitors are required to submit to Commission staff an annual state of the market report and less extensive quarterly reports. See Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281, at P 424 (2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 (2009), order on reh'g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).

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61.  RTO/ISO market monitors include a variety of competition metrics in their reports but these metrics are not used to mitigate prices in RTO/ISO markets. The market reports for each RTO/ISO do not reference the indicative screens.

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62.  ISO-NE uses both supply-side and demand side concentration measurements which measure the concentration of the four largest buyers and largest four sellers, expressed as a percentage of market share, similar to the market share screen used in the indicative screens.

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63.  The pivotal supplier tests are similar to the ones used in the indicative screens and determine if a supplier is pivotal if demand cannot be met without their supply. CAISO's market monitor reports on one, two, and three pivotal supplier tests.

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64.  The residual supply index is the ratio of supply from non-affiliate suppliers to demand.

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65.  The Lerner index measures the percentage markup that a firm is able to charge over its marginal cost. The index ranges from a low value of 0 to a high of 1. The higher the value of the Lerner index, the more the firm is able to charge over its marginal cost. The Lerner index measures seller behavior rather than market structure.

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66.  RTOs/ISOs use different methods to define constraints, and some RTOs/ISOs define constraints (specifically constrained areas) on an annual basis while others define constraints more dynamically.

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67.  SPP Open Access Transmission Tariff, Sixth Revised Volume No. 1, Attachment AF, Section 3.3.

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68.  CAISO Open Access Transmission Tariff, section 39.7.1.

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69.  See Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 831, FERC Stats. & Regs. ¶ 31,387, at P 1 (2016), (CROSS-REFERENCED AT 157 FERC ¶ 61,115), order on reh'g and clarification, Order No. 831-A, 161 FERC ¶ 61,156 (2017).

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70.  Order No. 831, FERC Stats. & Regs. ¶ 31,387, at P 1.

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71.  The indicative screens and subsequent granting of market-based rate authority does not place a must-offer requirement on sellers to address physical withholding.

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72.  ISO-NE's forward reserve market is not mitigated.

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73.  The price for ancillary services that are co-optimized with energy are derived from the LMP for energy. Therefore, mitigation of LMPs indirectly mitigates the price for such ancillary services.

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74.  The ISO-NE internal market monitor monitors ancillary services and reports on their performance and competitiveness. The CAISO market monitor routinely reports on the ancillary service markets, including costs, cost drivers, and operational issues. In the 2016 Annual Report, the market monitor did not raise any concerns that ancillary service markets were not competitive. See CAISO Department of Market Monitoring, 2016 Annual Report on Market Issues & Performance, (May 2017) http://www.caiso.com/​Documents/​2016AnnualReportonMarketIssuesandPerformance.pdf. See Chapter 6, Ancillary Services.

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75.  Reference levels set according to going-forward costs are generator specific.

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76.  Market-based rate sellers are authorized to sell certain ancillary services in CAISO and SPP at market-based rates. We do not propose to modify this authorization in the instant rulemaking.

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77.  See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 111 (“to the extent a seller seeking to obtain or retain market-based rate authority is relying on existing Commission-approved [RTO] market monitoring and mitigation, we adopt a rebuttable presumption that the existing mitigation is sufficient to address any market power concerns.”) For those RTOs and ISOs lacking an RTO/ISO-administered capacity market, Commission-approved RTO/ISO monitoring and mitigation will no longer be presumed sufficient to address horizontal market power concerns for capacity sales where there are indicative screen failures.

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78.  Under this proposal, a market-based rate seller participating in the CAISO Energy Imbalance Market but located outside of CAISO would still have to submit indicative screens for its relevant geographic market. The requirement to submit indicative screens is unchanged for market-based rate sellers in all traditional markets.

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79.  See Niagara Mohawk Power Corp., 123 FERC ¶ 61,175, at P 28 (2008) (failures in the New York City and Long Island submarkets of the New York Independent System Operator, Inc.); Dominion Energy Marketing, Inc., 125 FERC ¶ 61,070, at PP 26-27 (2008) (failures in the Connecticut submarket of ISO New England, Inc.); PSEG Energy Resources & Trade LLC, 125 FERC ¶ 61,073, at PP 31-32 (2008) (failures in the PJM-East submarket)). There are also numerous delegated letter orders granting sellers market-based rate authority where the seller relies on Commission-approved monitoring and mitigation in RTO markets. See, e.g., TransCanada Energy Marketing ULC, Docket No. ER07-1274-001 (Jan. 23, 2009) (delegated order). Finally, the Commission has not initiated any investigations pursuant to Federal Power Act section 206 for any RTO/ISO sellers failing indicative screens since the issuance of Order No. 697; in all cases where RTO/ISO sellers failed, the Commission relied on the Commission-approved monitoring and mitigation to prevent the seller's ability to exercise any potential market power.

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80.  On average per year, approximately 20 indicative screens from this total studied the CAISO and SPP markets.

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81.  Market-based rate sellers would also continue to submit other information, such as ownership and affiliate information. See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 181 n.258 (“A seller seeking market-based rate authority must provide information regarding its affiliates and its corporate structure or upstream ownership.”); 18 CFR 35.37(a)(2) (requiring submission of an organizational chart); however, the requirement to submit an organizational chart is currently stayed. See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 47. Sellers also would continue to be required to provide the following additional information: (1) A standard vertical market power analysis; (2) category status representations; (3) a demonstration that sellers continue to lack captive customers in order to support obtaining or retaining a waiver of affiliate restrictions, if requested; and (4) any other information that is required for that particular filing. See 18 CFR 35.37.

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82.  See 18 CFR 35.10b. EQRs are discussed in more detail below.

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84.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 506 (“[W]e will not require entities to automatically file an updated market power analysis with their change in status filings . . . . Furthermore, regardless of the seller's representation, if the Commission has concerns with a change in status filing (for example, market shares are below 20 percent, but are relatively high nonetheless), the Commission retains the right to require an updated market power analysis at any time.”).

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85.  As discussed above, the price of several ancillary services reflects the opportunity cost of not selling energy, so mitigation of energy prices will affect the price of such ancillary services offered in the day-ahead and real-time markets.

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86.  See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 111.

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87.  We recognize that challenging parties would have to provide evidence that a seller had market power before arguing that RTO/ISO mitigation was insufficient to address the seller's alleged market power. In addition to the information provided by a seller in its market-based rate filings, a challenging party could rely on other sources to present evidence that a seller has market power. Moreover, a challenging party is not limited as to the type of tests or other evidence it submits to make such a demonstration.

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88.  Short-term forward contracts (e.g., of daily or weekly duration) typically are standardized contracts, whereas long-term contracts (defined as one year or longer) often are negotiated, tailored contracts between the buyer and seller.

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89.  Financial transactions can provide buyers and sellers a hedge against uncertain and volatile day-ahead energy prices and typically are settled against the energy prices published by RTOs/ISOs.

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90.  We recognize that RTO/ISO energy and capacity markets are not necessarily a perfect substitute for bilateral sales, particularly if the bilateral sale is made pursuant to a non-standardized, long-term contract. However, RTO/ISO energy and capacity markets provide load-serving entities a means to serve their customers and also provide a benchmark against which to compare prices offered in the bilateral market.

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91.  Order No. 816 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 35.

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92.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 285.

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93.  See supra section II.C.

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94.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 963.

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95.  See 18 CFR 35.37(a)(2), 35.37(d). While the requirement to submit an organizational chart is currently stayed, market-based rate sellers still must provide information regarding their affiliates and corporate structure or upstream ownership. Sellers seeking to obtain or retain market-based rate authority must trace upstream ownership until all upstream owners are identified. In addition, market-based rate sellers must identify all of their affiliates and, when seeking market-based rate authority, state the business activities of its owners and state whether such owners are in any way involved in the energy industry. See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 181 n.258.

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96.  See 18 CFR App. A to subpt. H of pt. 35.

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97.  Information provided in the indicative screens does not support the analysis of vertical market power. Thus, the screens do not provide insight into the ability of a vertically-integrated company to use its transmission assets to favor its generation assets.

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98.  See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 301, 304; Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 126.

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99.  Change in status filings, which currently do not require the submission of indicative screens, are a useful tool in assessing a seller's ability to exercise market power. We will, therefore, retain this requirement for RTO/ISO sellers.

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100.  See 18 CFR 35.10b. The EQR requirement also applies to non-public utilities with more than a de minimis market presence. Id.

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101.  See Electric Market Transparency Provisions of Section 220 of the Federal Power Act, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,675, at P3 (2011) (citing Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 (May 8, 2002), 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, 72 FR 56735 (Oct. 4, 2007), 120 FERC ¶ 61,270, order on reh'g and clarification, Order No. 2001-H, 73 FR 1876 (Jan. 10, 2008), 121 FERC ¶ 61,289 (2007), order revising filing requirements, Order No. 2001-I, 73 FR 65526 (Nov. 4, 2008), 125 FERC ¶ 61,103 (2008)).

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102.  Electric Market Transparency Provisions of Section 220 of the Federal Power Act, FERC Stats. & Regs. ¶ 32,675 at P3 (citing Order No. 2001, FERC Stats. & Regs. ¶ 61,127 at P 31).

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103.  Electricity Mkt. Transparency Provisions of Section 220 of the Federal Power Act, Order No. 768, FERC Stats. & Regs. ¶ 31,336, at P 1 (2012) (cross-referenced at 140 FERC ¶ 61,232), order on reh'g and clarification, Order No. 768-A, 143 FERC ¶ 61,054 (2013).

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104.  The Commission's default mitigation for sellers that fail market power screens may be found at 18 CFR 35.38. Mitigation for short-term sales—sales of one week or less—is set equal to the seller's incremental cost plus a ten percent adder. This mitigation is very similar to an RTO/ISO seller's reference level price, as discussed above.

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106.  The Commission has flexibility in how it ensures that rates are just and reasonable. The Supreme Court has previously found that, while statutes such as the Natural Gas Act, and the Federal Power Act direct that rates be just and reasonable, they do not specify the means by which that is to be attained. See FPC v. Texaco, Inc., 417 U.S. 380, at 387 (1974). Furthermore, the Commission has previously found that it is not an impermissible subdelegation of its responsibility to ensure just and reasonable rates when it approves certain RTO/ISO actions as detailed in Commission-approved RTO/ISO tariffs. See e.g., Midwest Indep. Transmission Sys. Operator, Inc., 111 FERC ¶ 61,053, at P 25, order on reh'g, 112 FERC ¶ 61,086 (2005); also Midwest Indep. Transmission Sys. Operator, Inc., 136 FERC ¶ 61,100, at P 31 (2011); San Diego Gas & Elec. Co. v. Sellers of Energy & Ancillary Servs. 127 FERC ¶ 61,269, at P 109 (2009), order on reh'g, 131 FERC ¶ 61,144 (2010).

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107.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 963 (footnotes omitted).

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108.  The Commission has flexibility in how it ensures that rates and just and reasonable. The Supreme Court has previously found that, while statutes such as the Natural Gas Act, and the Federal Power Act direct that rates be just and reasonable, they do not specify the means by which that is to be attained. See FPC v. Texaco, Inc., 417 U.S. 380, at 387 (1974).

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109.  Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 112.

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110.  See Midwest Indep. Transmission Sys. Operator, Inc., 136 FERC ¶ 61,100, at P 31 (2011); La. Pub. Serv. Comm'n, 761 F.3d 540, 552 (5th Cir. 2014).

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113.  “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.

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116.  Other Sellers in the chart below are market-based rate sellers that do not have an RTO/ISO market with RTO/ISO-administered energy, ancillary services, and capacity markets as a relevant geographic market.

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117.  Due to the fact that change in status requirements may include the indicative screens in their market power analysis depending on the change reported, but are not necessary, we estimate the change in burden for change in status filings is de minimis. See 18 CFR 35.42.

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118.  The Commission estimates this figure based on the Bureau of Labor Statistics data (for the Utilities sector, at http://www.bls.gov/​oes/​current/​naics2_​22.htm, plus benefits information at http://www.bls.gov/​news.release/​ecec.nr0.htm). The salaries (plus benefits) for the three occupational categories are:

Economist: $71.98/hour.

Electrical Engineer: $60.90/hour.

Lawyer: $143.68/hour.

The average hourly cost of the three categories is $92.19 [($71.98 + $60.90 + $143.68)/3].

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119.  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).

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121.  18 CFR 380.4(a)(2)(ii).

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124.  In 13 CFR 121.201, Subsector 221, the Commission uses the North American Industry Classification System codes 221122 (Electric Power Distribution), 221121 (Electric Bulk Power Transmission and Control), 221113 (Nuclear Electric Power Generation), 221114 (Solar Power Electric Power Generation), and 221115 (Wind Power Electric Generation). The highest threshold among these NAICS codes results in any respondent entities below 1,000 employees being considered as “small.”

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125.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 1126-1129.

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126.  Category 1 Sellers are power marketers and power producers that own or control 500 MW or less of generating capacity in aggregate and that are not affiliated with a public utility with a franchised service territory. In addition, Category 1 sellers must not own or control transmission facilities, and must present no other vertical market power issues. 18 CFR 35.36(a)(2).

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[FR Doc. 2019-00459 Filed 1-31-19; 8:45 am]

BILLING CODE 6717-01-P