FERC Proposes to Reduce Market-Based Rate Statistical Study Requirements in Some Organized Markets

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The Federal Energy Regulatory Commission issued a Notice of Proposed Rulemaking on December 20 that would partially relax the competitive market power study requirements that apply to public utilities with Market-Based Rate authority. This LawFlash analyzes the proposal—Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets—and discusses the implications for market-based rate sellers if it is adopted.

Sellers of wholesale electricity in the United States—including generating companies and traditional, franchised utilities—are typically required to obtain “Market-Based Rate” (MBR) authority[1] from the Federal Energy Regulatory Commission (Commission or FERC) prior to commencing any deliveries of wholesale electricity under any rate or contract other than FERC-approved cost-of-service rates. Thousands of entities, most of them independent generating firms, hold MBR authority and do business within FERC’s organized “independent system operator” and “regional transmission organization” (ISO/RTO) markets. Only specified classes of entities, typically traditional franchised utilities, sell electricity at cost-based rates, and only limited classes of electricity wholesale sellers (such as government-owned utilities[2] and some smaller “Qualifying Facility” generators[3]) need not receive FERC permission prior to selling power.

In a new Notice of Proposed Rulemaking (the NOPR),[4] FERC is proposing to dispense with some of the more burdensome and time-consuming statistical study requirements MBR entities must follow to demonstrate that they lack market power and therefore qualify to hold MBR authority.  But although the proposal would simplify the compliance obligations of such entities to a degree, the improvements would only be in some respects and only within a subset of the Commission-regulated ISO/RTO power markets.

Background

FERC imposes strict and intricate market power limits on MBR eligibility. An entity seeking to obtain or to renew its MBR authority must fully disclose to FERC, in a public application, its ownership and control; the disclosures must also include an enumeration of the electric generating and certain fuel- and transmission-related affiliates of the MBR entity and its direct and indirect parents. These disclosures must then be distilled into statistical market power studies, demonstrating that the MBR entity’s and all of its affiliates, taken collectively, do not exhibit an unacceptably high wholesale market share in each season of the study year that FERC selects, and are not pivotal (or physically critical) in each relevant geographic market.[5]

In practical terms, FERC’s requirements mean that even a relatively small generator with a slim amount of uncommitted capacity must prepare no less than five statistical market power studies as part of its already intricate initial MBR application. Complicating the requirements is the fact that, in several large markets (including the Mid-Atlantic grid operator PJM Interconnection, L.L.C. (PJM), and the New York Independent System Operator (NYISO)) include submarkets[6] that must be studied as well. In PJM, several of those submarkets geographically overlap,[7] so some MBR applicants owning or affiliated with generation in PJM must submit four study sets, including a total of twenty separate statistical market power screens. A larger generating complex must redo all of its studies as part of a FERC triennial market-power filing requirement.[8] And every MBR entity may be required to file re-studies of its market power whenever the MBR entity’s affiliations change, or whenever the MBR entity experiences what FERC terms a “change in status,” in any relevant market.[9]

The NOPR

The NOPR recognizes that statistical market screens are of limited value within heavily policed ISO/RTO markets,[10] and proposes to dispense with the market screens for MBR entities (including new applicants) that

  • are within an ISO/RTO market, if
  • the applicable ISO/RTO administers energy, ancillary services, and capacity markets, but only when
  • the ISO/RTO is subject to Commission-approved monitoring and mitigation.[11]

If FERC ultimately adopts the NOPR, then an MBR entity within an ISO/RTO that both (1) administers all three forms of market that the NOPR identifies; and (2) is subject to FERC-approved market monitoring, need not submit statistical market power screens as part of the MBR entity’s ordinary-course filings with FERC.

However, FERC has indicated that it will continue to reserve the right to require an MBR entity to prepare and submit statistical screens whenever it appears that an MBR entity (again, taken together with its FERC-defined “affiliates”) might possess market power.[12] In addition, in both initial MBR applications and in ongoing compliance filings, FERC will continue to require MBR entities to fully disclose their ownership, control, “affiliations” with generating capacity and assets, and its affiliation with vertical inputs into wholesale power production, such as fuel and transmission businesses and assets.[13]

What the NOPR Does Not Do

Many MBR entities may not be directly affected by final rule that the NOPR proposes. For example, MBR entities in the California Independent System Operator (CAISO) or Southwest Power Pool (SPP) ISO/RTO territories have no ISO/RTO capacity market; MBR entities in these markets would be required to submit and pass the current versions of FERC’s statistical screens if they wish to make any sales of uncommitted capacity.[14] MBR entities doing business outside the eligible ISO/RTO markets will be required to continue their compliance with the existing statistical screen requirements. And those MBR entities within ISO/RTO markets that in the past have failed statistical screen requirements but have accepted ISO/RTO mitigation requirements[15] in lieu of passing the arithmetic standards will no longer be permitted to do so, and will instead become subject to considerably more intrusive and less expressly defined requirements.[16]

If the proposed rule in the NOPR becomes effective, a generation company with MBR authority that sells into both (1) ISO/RTO territories that have no ISO/RTO capacity market (i.e., SPP and CAISO); and (2) ISO/RTO territories that operate RTO/ISO-administered energy, ancillary services, and capacity markets (i.e., PJM, ISO-NE, NYISO, and MISO) will still be required to submit screens for the market(s) that are not within the Commission’s new proposal to relax the statistical screen requirements. This reflects a reduction, but not the elimination, of current screen submission burdens on certain multi-market generation sellers.

Comments and Timing

FERC will accept comments on the NOPR for 45 days following the NOPR’s publication in the Federal Register. Following the receipt of comments and any reply comments, FERC can be expected to take at least 30 to 60 days to issue a final rule, which in turn is not likely to become effective for an additional 60 days.


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

[2] Pursuant to Section 201 of the Federal Power Act, as amended, certain governmental utilities are not subject to direct FERC rate or corporate regulation. 16 U.S.C. § 824a.

[3] See, 18 C.F.R. § 292.601(c).

[4] Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets, Notice of Proposed Rulemaking, Docket No. RM19-2-000 (December 20, 2018), 165 FERC ¶ 61,268 (2018).

[5] See generally, 18 C.F.R. § 35.37.

[6] In PJM, the Commission initially identified one submarket: PJM East. In its examination of a merger, in Docket Nos. EC11-83-000 et al., the Commission identified and considered two additional submarkets within PJM. These two additional submarkets are referred to as the AP South and 5004/5005 submarkets. New York City and Long Island are separate markets within NYISO.

[7] PJM East comprises a portion of the 5004/5005 submarket, and the 5004/5005 submarket comprises a portion of the AP South submarket. See, e.g. Luminant Energy Company LLC, Docket No. ER19-102-000, 165 FERC ¶ 61,222 (2018), Order On Market-Based Rate Filing And Updated Simultaneous Transmission Import Limit Values; New Brunswick Energy Marketing Corporation, et al., Order On Simultaneous Transmission Import Limit Values For The Northeast Region, Docket No. ER14-225-002, 147 FERC ¶ 61,190 (2014).

[8] 18 C.F.R. § 35.37(a)(1).

[9] 18 C.F.R. § 35.42.

[10] See NOPR at ¶¶ 8 (“the burden of submitting indicative screens may not be ‘outweighed by the additional information gleaned with respect to a specific seller’s market power’.”, 27 (“the burden on sellers to provide indicative screens may outweigh the benefits in certain RTO/ISO markets”) and 45 (“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.”).

[11] See NOPR at ¶ 23.

[12] See NOPR at ¶ 60 and 18 C.F.R. § 35.37(a)(1) (“a Seller must submit a market power analysis . . . any other time the Commission directs a Seller to submit one.”)

[13] See NOPR at ¶ 63.

[14] See NOPR at ¶ 41.

[15] The Commission’s default mitigation for sellers that fail market power screens is found at 18 C.F.R. § 35.38.

[16] See NOPR ¶ 51 and n. 77.

 

DISCLAIMER: Because of the generality of this update, the information provided herein may not be applicable in all situations and should not be acted upon without specific legal advice based on particular situations.

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